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Winter 2014

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGYA quarterly publication of the Saudi Arabian Oil CompanyJournal of Technology

Saudi Aramco

Contents

Shale Gas Characterization and Property Determination by Digital Rock Physics 2Anas M. Al-Marzouq, Dr. Tariq M. Al-Ghamdi, Safouh Koronfol, Dr. Moustafa R. Dernaika and Dr. Joel D. Walls

Chemically Induced Pressure Pulse: A Novel Fracturing Technology for Unconventional Reservoirs 14Ayman R. Al-Nakhli, Dr. Hazim H. Abass, Mirajuddin R. Khan, Victor V. Hilab, Ahmed N. Rizq and Ahmed S. Al-Otaibi

Integrating Intelligent Field Data into Simulation Model History Matching Process 25Bevan B. Yuen, Dr. Olugbenga A. Olukoko and Dr. Joseph Ansah

Borehole Casing Sources for Electromagnetic Imaging of Deep Formations 34Dr. Alberto F. Marsala, Dr. Andrew D. Hibbs and Prof. Frank Morrison

Laboratory Study on Polymers for Chemical Flooding in Carbonate Reservoirs 41Dr. Ming Han, Alhasan B. Fuseni, Badr H. Zahrani and Dr. Jinxun Wang

Sweet Spot Identification and Optimum Well Planning: An Integrated Workflow to Improve the Sweep in a Sector of a Giant Carbonate Mature Oil Reservoir 52Dr. Ahmed H. Alhuthali, Abdullah I. Al-Sada, Abdullah A. Al-Safi and Mohamed T. Bouaouaja

Innovation in Approach and Downhole Equipment Design Presents New Capabilities for Multistage Stimulation Technology 61Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Mustafa R. Al-Zaid and Fadel A. Al-Ghurairi

Deploying Global Competition by Innovation Network for Empowering Entrepreneurship, Venturing and Local Business Development: A Case Study — Desalination Using Renewable Energy 70Dr. M. Rashid Khan

ABSTRACT compared to the clay-rich facies. This is mainly caused by thepressure compaction effect on the soft clay-rich samples. Highpercentages of organic matter were not found to be a good in-dication for high porosity or permeability in the clay-rich shalesamples, while the depositional facies was found to have a greateffect on the pore types, rock fabric and reservoir properties.The results and interpretations in this study provide further insights and enhance our understanding of the heterogeneity ofthe organic-rich shale reservoir rock.

INTRODUCTION

Hydrocarbon recovery factors from unconventional organic-rich shale have always been at the lower end of historic figuresfrom conventional reservoirs1. The reason for this is the ultra-low permeability of the rock, which requires massive hydraulicfracturing to enhance connectivity, and therefore, permeabilityfor the flow. The fracturing technique should have the poten-tial to lead to economical hydrocarbon production by creatinga complex fracture network that is made up of many intercon-nected fractures in close proximity to one another. To choosethe right fracturing technique, one must have a good under-standing of the reservoir characteristics at multiple scales. Theevaluation of shale, however, is complicated by the structurallyheterogeneous nature of the fine-grained strata and their intri-cate pore networks, which are interdependent on many geo-logic factors, including total organic carbon (TOC) content,mineralogy, maturity and grain size.

In this work, full-diameter whole core samples from a shalegas reservoir in the Middle East were characterized at the coreand pore scale levels. The core samples were analyzed usingthe dual-energy X-ray computed tomography (XCT) scanningtechnique to locate potentially high quality rock intervals withhigh porosity and high TOC. Data acquired from 2D scanningelectron microscopy (SEM) and 3D focused ion beam (FIB)-SEM analysis were studied to characterize the kerogen contentin the samples, together with (organic and inorganic) porosityand rock fabric. The mineral framework of the samples wasdetermined from energy dispersive spectroscopy (EDS) analy-sis. The FIB-SEM images in 3D were used to determine poros-ity and TOC by segmentation and to determine directionalpermeability by the Lattice Boltzmann method (LBM). Trends

Unconventional shale reservoirs differ largely from conventionalsandstone and carbonate reservoirs in their origin, geologicevolution and current occurrence. Shale comprises a wide varietyof rocks that are composed of extremely fine-grained particleswith very small porosity values on the order of a few porosityunits and very low permeability values in the nanodarcy (nD)range. Shale formations are very complex at the core scale:they exhibit large vertical variations in lithology and total or-ganic carbon (TOC) at a scale so small that it renders corecharacterization and sweet spot detection very challenging.Shale formations are also very complex at the nano-scale level,where pores having different porosity types are detected withinthe kerogen volume. These complexities have led to further research and the development of an advanced application ofhigh resolution X-ray computed tomography (XCT) scanningon full-diameter core sections to characterize shale mineralogy,porosity and rock facies so that accurate evaluation of thesweet spot locations can be made for further detailed petro-physical and petrographic studies.

In this work, argillaceous shale gas cores were imaged usinghigh resolution dual-energy XCT scanning. This imaging tech-nique produces continuous whole core scans at 0.5 mm spacingand derives accurate bulk density (BD) and effective atomicnumber (Zeff) logs along the core intervals, logs that are crucialin determining lithology, porosity and rock facies. Additionally,integrated X-ray diffraction (XRD) data and energy dispersivespectroscopy (EDS) analysis results were acquired to confirmthe mineral framework composition of the core. Smaller coreplugs and subsamples representing the main variations in thecore then were extracted for much higher resolution XCTscanning and scanning electron microscopy (SEM) analysis.Porosity, mainly found in organic matter, was determined from2D and 3D SEM images by the image segmentation process.Horizontal fluid flow was only possible through the organicmatter and the simulations of 3D focused ion beam (FIB)-SEMvolumes by solving the Stokes equation using the Lattice Boltz-mann method (LBM).

A clear trend was observed between porosity and permeabil-ity, correlating with identified facies in the core. Silica-rich faciesgave higher porosity-permeability relationship characteristics

Shale Gas Characterization and Property Determination by Digital Rock Physics

Authors: Anas M. Al-Marzouq, Dr. Tariq M. Al-Ghamdi, Safouh Koronfol, Dr. Moustafa R. Dernaika and Dr. Joel D. Walls

2 WINTER 2014 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

were obtained among the computed data, in addition to theTOC and rock fabric values that are necessary for proper shaleevaluation and completion considerations.

A clear trend was observed between porosity and permeabil-ity in relation to identified facies in the core. Silica-rich faciesgave higher poroperm characteristics compared to the clay-richfacies. The depositional facies was found to have a profoundeffect on the pore types, rock fabric and reservoir properties.

DUAL-ENERGY COMPUTED TOMOGRAPHY IMAGING

XCT imaging is a powerful nondestructive technique used inthe oil industry to evaluate the internal structures of cores. Theacquisition of high resolution continuous images along thecore length is essential in complex reservoirs to characterizereservoir heterogeneity and optimize sample selection for fur-ther detailed analysis. Dual-energy computed tomography(CT) scanning involves imaging the core at two energy levels atthe same location. This dual-energy imaging provides two dis-tinct 3D images of the core by using a high and a low energysetting. The high energy images are slightly more sensitive tobulk density (BD) — Compton scattering effect — and the lowenergy images are slightly more sensitive to mineralogy —photoelectric absorption effect2. The high resolution computedBD values and effective atomic number (Zeff), or photoelectricfactor (PEF), values can be used in shale formations to inter-pret and quantify porosity, organic content (for identifyingsweet spots) and mineralogy. When combined with other com-monly available information, such as core spectral gammadata, more complex analyses can be performed. For example,the elastic properties and brittleness index can be determined3.Recently, the technique has been used in complex carbonateand sandstone reservoirs in the Middle East to characterizereservoir heterogeneity and optimize the sample selection forspecial core analysis testing4-6. In cases of poor core recoveryand drilling mud invasion, it becomes more practical to corre-late the CT data to density logs or photoelectric logs instead ofthe natural gamma ray logs.

CORE CHARACTERIZATION AND SAMPLE SELECTION

Dual-energy CT scanning was performed on a total of 49 ft ofcore (49 discontinuous 1 ft sections) from a shale source rockreservoir in the Middle East. The dual-energy logs in Figs. 1aand 1c provided accurate BD and PEF data, respectively, alongcore lengths that were used to characterize the core sectionsand to efficiently identify sweet spots for the representative se-lection of plug sampling locations. Shale formations are oftencomposed of stacked para-sequences7 that are quite thin anddifficult to detect from well logs. This high resolution datafrom the whole core therefore provides a powerful tool to de-fine these para-sequences.

Figure 1d plots the PEF data with reversed scale BD to high-light the best quality shale intervals, with the largest gap

presented in green. In this perspective, low PEF values (around1.8) and low BD (<2.4) would indicate silica-rich shale withlow clay content and high porosity. Five different facies weredetected and highlighted in Fig. 1b. Figure 2 plots the BD datavs. PEF with the highlighted facies. Reference lines for themain minerals are shown in the figure to indicate mineralogyvariations in the core. It is clear from Fig. 2 that this core con-tains no calcite minerals. The five different color facies wereidentified as follows and summarized in Table 1:

• Green facies: Data with low density and low PEF. When

SAUDI ARAMCO JOURNAL OF TECHNOLOGY WINTER 2014 3

Fig. 2. BD vs. PEF for all dual-energy CT data. Color cutoffs were identified fromFig. 1d to highlight variations in shale properties. Reference lines for the mainminerals are shown in the figure to indicate mineralogy variations in the core.

Fig. 1. Dual-energy CT data along 49 discontinuous 1 ft core sections: (a) BD,(b) identified facies, (c) PEF, (d) PEF with reversed BD, and (e) radial cross-sectional images.

BD is reversed as in Fig. 1d, it creates the largest gap be-tween the PEF and ROHB curves. This identifies the po-tential regions for silica-rich shale with high porosity/or-ganic matter and low clay content (sweet spots). This be-havior is clearly shown in one of the zoomed intervals as represented by Fig. 3a.

• Red facies: Data with medium density and medium PEF. When BD is reversed, it creates a small gap between the curves. This identifies potential regions for clay-rich shalewith low porosity/high organic matter and low silica con-tent. This behavior is clearly shown in one of the zoomed intervals as represented by Fig. 3b.

• Black facies: Data with high density and low-to-medium PEF. When BD is reversed, it creates no gap between the curves. This identifies potential regions for silica-rich shale with very low porosity/low organic matter and low clay content. This behavior is clearly shown in one of the zoomed intervals as represented by Fig. 3c.

• Blue/yellow facies: Data with high density and medium PEF. When BD is reversed, it creates a large gap between the curves filled with blue. This identifies potential re-gions for clay-rich shale with very low porosity/low organic matter and low silica content. The larger gap in thisgroup indicates denser layers, which are indicated with yellow; the layers are otherwise blue, as can be clearly seen in the “facies” and “radial image” columns in Fig. 3d.

Table 1 provides only qualitative indications for the faciesvariations in the cores and should be confirmed by further de-tailed analysis using X-ray diffraction (XRD), EDS and SEM.It should also be noted that (in this analysis) each color facieshas a range of dual-energy data that allows for shale propertyvariations within the same facies. Therefore, the description inTable 1 should be used only to locate potentially high qualityshale for sampling and further analysis.

Facies-based Sample Selection

Figure 4 combines wireline log data with the dual-energy XCTderived data. In column (c) the BD data from dual-energy CTshows a reasonable match with the wireline density log. Column (h) shows the percentage of quartz obtained from theXRD analysis performed in selected locations in the core to

confirm the facies distribution determined from dual-energyCT and described in Table 1. High quartz percentages from theXRD data confirmed the green facies in the core and the faciesdescription in Table 1. Similarly, column (j) shows high clayconcentrations from the XRD data for the red and yellow facies,which are characterized by medium-to-high PEF values, therebyconfirming the descriptions in Table 1. The nine arrows in


Color Facies Porosity Organic

Matter Silica Clay Carbonate

Green High High High Low Low

Red Low High Low High Low

Black Very low Low High Low Low

Blue/Yellow Very low Low Low High Low

Table 1. Potential description of each identified facies in the cores based on PEF andBD values from dual-energy CT data

(a) green facies, large green fill (low PEF, low BD)

(b) red facies, small green fill (medium PEF, medium BD)

(c) black facies, small blue fill (medium PEF, high BD)

(d) blue/yellow facies, large blue fill (medium PEF, high BD)

Fig. 3. Example of color facies based on the dual-energy CT data from Fig. 1d.

Fig. 4g indicate the selected plug sampling locations in the corefor further shale characterization. Five samples were cut fromthe green facies (identified sweet spot), three from the red fa-cies and one from the yellow facies.

The goal of this facies analysis and sample selection is to ex-plore the possible links between shale depositional facies andpore types in shale rocks. This will enhance our understandingof the overall reservoir quality. It is also our goal to quantifythe relationship between porosity and matrix permeability foreach identified facies in the core. Identifying such trends ofporoperm data and facies would facilitate upscaling, reservesestimation and well-to-well correlation.

PETROPHYSICAL PROPERTIES

Laboratory-based core analysis data on shale rocks are verydifficult to obtain due to the tight nature of these rocks. Tradi-tional laboratory evaluation methods may not be applicable toshale, and therefore the continued development of laboratorymethods is required to help characterize and understand chal-lenging shale reservoir behaviors. In recent years, digital imagingtechnology has been extensively used in the petroleum indus-try, including in shale formations8, to obtain fast and reliablecore data such as porosity and permeability. The new emergingtechnology has been called digital rock physics (DRP) and has

contributed reliably to the computations of reservoir propertiesthrough image segmentation in 3D and direct simulation4, 9-11.

Micro XCT Imaging

Each selected plug sample from the nine whole cores wasscanned with a micro XCT scanner at a resolution of 40 mi-crons per voxel. A series of multiresolution scans was then acquired, down to 4 microns per voxel, to evaluate the micro-scale heterogeneity and to scout for an optimal location in thesample for further SEM analysis. These micro XCT scans werecombined with X-ray fluorescence readings to characterize theelemental composition of the sample and to locate a regionthat could adequately represent the sample. Figure 5 presentsan example of such images from Sample #1.

2D SEM

In Fig. 5d, a representative region (outlined in red) was se-lected for 2D SEM overview. The 2D SEM area was extractedand polished with a broad ion beam, resulting in a smooth sur-face of approximately 1,000 by 500 microns. That surface wasimaged at a resolution of approximately 250 nanometers (nm)per pixel. Then a series of high resolution SEM images was acquired perpendicular to the lamination at a resolution of 10


Fig. 4. (a) wireline gamma ray, (b) total gamma, (c) wireline density vs. duel-energy density, (d) identified facies from dual-energy CT, (e) PEF from dual-energy CT, (f) PEFwith reversed BD from dual-energy CT, (g) recommended sampling locations, (h) % quartz from XRD data, (i) wireline neutron/density, (j) % clay minerals from XRD data,(k) potassium log, (l) thorium log, and (m) uranium log. Arrows in column (g) indicate selected plug locations for further porosity, permeability and TOC characterization.Arrow colors refer to identified facies from dual-energy CT.

nm per pixel. It is at this resolution that we were able to ob-serve and quantify porosity and organic matter content. Figure6 shows a representation of this analysis. Images were seg-mented for total porosity, porosity in organic matter, organicmatter and high density. These results were used to choose onerepresentative image with high porosity and high organic mat-ter for 3D FIB-SEM. The segmented data for all the nine plugsamples are shown in Table 2. The identified facies from thenine samples link very well with the segmented porosity andorganic matter percentages. As described in Table 1 from thedual-energy CT data in the core, Table 2 shows that the greenfacies has the highest porosity, the red facies has low porosity,and the yellow facies has very low porosity. The pictures of

selected 2D SEM images from the different facies shown in Fig.7 confirm the obtained data in Table 2.

3D FIB-SEM

The area of interest in Fig. 6g was imaged in 3D at a resolu-tion of 15 nm per voxel using FIB-SEM imaging and digital reconstruction techniques. Rock matrix materials, organicmatter and porosity were individually identifiable via theirunique gray scale signatures. Each of the 3D volumes from theplug samples was digitally analyzed, and volumetric percent-ages of organic matter and total porosity were determined. Theporosity was further analyzed and quantified as connected,


Fig. 6. 2D SEM images from plug Sample #1: (e) 2D SEM overview image at 250 nm/pixel selected from the XCT image at 4 microns/pixel (d); (f) a set of 10 highresolution 2D SEM images at 10 nm/pixel; (g) one representative high resolution 2D SEM image chosen for 3D FIB-SEM (the 3D area of interest is outlined in red).

Fig. 5. Multiresolution XCT images from whole core at (a) 500 microns/voxel down to (d) XCT at 4 microns/voxel.

non-connected and associated with organic matter. The con-nected porosity was used to compute absolute permeability di-rectly in the 3D digital rocks in the horizontal and (wheneverpossible) vertical directions using the LBM12. Porosity associ-ated with organic matter can be an indicator of organic mattermaturity and flow potential. Table 3 gives the segmented val-ues from the 3D FIB-SEM volumes. The table also gives calcu-lations of the conversion ratio, and the organic porosity andtotal porosity in percentages. The conversion ratio percentwould represent the porosity within the organic matter withrespect to the organic matter volume, while the organic-to-to-tal porosity percent would represent the percentage of pores inthe organic matter with respect to the total porosity in the 3Dvolume. The 3D volume data in Table 3 is a clear confirmationof the potential relationship among facies, pore type, porosityand flow characteristics in shale. Both the red and green facieshave high percentages of organic matter, but the red facies areat the lower range of porosity, which influenced the flow prop-erties and thereby yielded much lower matrix permeabilities

than the green facies samples. This can be quantified in Table 3by the conversion ratio values, which show higher than 30%for the green facies and lower than 20% for the red facies.These findings suggest that further analysis of the organic mat-ter and mineral framework in the red facies samples is requiredto determine the reasons behind the lower conversion ratios.Sample #9 was excluded from the 3D FIB-SEM analysis be-cause the sample showed no flow potential due to the very lowporosity in the 2D SEM image in Fig. 7 and Table 2.

Figure 8 shows video snapshots from the different facies withtheir different permeability values. This figure serves as a goodvisual means to evaluate the simulated directional permeabilityvalues in Table 3. Sample #1 has low horizontal permeabilitywith low porosity in the organic matter. Sample #5 has higherhorizontal permeability and gave rise to flow in the vertical direction as well. Sample #8 has the highest horizontal perme-ability value, and the reason is clearly seen to be an unrepre-sentative streak of organic matter with relatively large poresizes. The permeability in these shale facies seem to be controlled


Fig. 7. Example 2D SEM images (at 10 nm/pixel) representing different facies that were identified at core scale.

Plug Sample # Core Facies Porosity (%) Organic Matter (%) Porosity in Organic Matter (%)

High Density Material (%)

1 Red 1.58 8.16 1.33 2.06

2 Red 1.51 9.91 1.34 1.74

3 Red 1.17 16.37 0.88 4.24

4 Green 3.09 13.48 2.73 2.99

5 Green 5.36 8.75 4.05 0.57

6 Green 3.95 6.02 2.66 0.53

7 Green 4.80 13.56 3.92 0.82

8 Green 2.63 5.01 1.84 2.46

9 Yellow 0.29 0.75 0.08 0.37

Table 2. Average values from the 10 2D SEM images for each plug sample

by the organic matter distribution and the porosity associatedwith the organic matter.

MINERALOGY

Areas of interest for the EDS analysis were selected to includethe analyzed 2D SEM images and the 3D area of interest. TheSEM-EDS area of interest is imaged at a resolution of approxi-mately 200 nm per pixel and covers an area of approximately200 by 150 microns. Table 4 gives the mineral volume percent-ages for all plug samples analyzed by EDS. The EDS resultsconfirm a clear link between mineralogy and the core facies asanalyzed from dual-energy CT data on the whole cores and aspreviously described in Table 1. The red and yellow facies areclay-rich shale with less than 25% silica, while the green faciesare silica-rich shale with less than 25% clay. One would thenbe tempted to think of a link between mineralogy and porositywhen comparing the red and green facies. These two facieshave similar fractions of organic matter but different porosity.The reason for this could be either maturation of kerogen orthe mineral framework of the samples.

XRD analysis was performed on all nine samples to confirm

the EDS mineralogy results. Table 5 gives the XRD data and confirms the EDS analysis. Figure 9 presents schematic compar-isons between the EDS and XRD analyses for Sample #1 from thered facies and Sample #6 from the green facies. EDS is repre-sented by the mineral distribution map and XRD by the pie chart.

EFFECTS OF DEPOSITIONAL FACIES ON PORE TYPES,ORGANIC MATTER, ROCK FABRIC AND RESERVOIRPROPERTIES

Shale pore systems may generally be described and classified asinter-granular (between grains), intra-granular (within grains)or organic matter13. Porosity within organic matter would beformed by the shrinkage of kerogen during maturation. The inter-granular and intra-granular pores are inorganic and so


Fig. 8. Example 3D FIB-SEM video snapshots (at 15 nm/pixel) representingdirectional flow for different samples.

Plug Sample #

Core Facies

Porosity (%)

Non-Connected

Porosity (%)

Organic Matter

(%)

Poros-ity in

Organic Matter

(%)

Absolute Permeability

(Kh) (nD)

Absolute Permeability

(Kv) (nD)

Conversion Ratio (%)

Porosity in OM/Total

Porosity (%)

1 Red 2.2 0.9 14.8 2.1 40 0 12.4 95.5

2 Red 2.5 0.8 9.3 2.2 19 0 19.1 88.0

3 Red 3.2 0.8 18.5 3.0 50 0 14.0 93.8

4 Green 6.1 1.5 11.4 5.1 102 0 30.9 83.6

5 Green 5.0 0.8 7.1 4.2 131 32 37.2 84.0

6 Green 6.4 1.2 9.3 5.6 348 21 37.6 87.5

7 Green 5.3 0.6 9.2 4.9 786 0 34.8 922.5

8 Green 7.7 1.2 10.1 6.8 6,111 0 40.2 88.3

Table 3. Values from 3D FIB-SEM volumes for each plug sample

Fig. 9. Comparisons between EDS (top) and XRD (bottom) analyses for Sample #1(red facies) and Sample #6 (green facies). EDS is represented by the mineraldistribution map and XRD by pie chart. Reference mineral phase is given for theEDS mineral maps, and legend is given for the XRD pie charts.


would normally be located in the matrix. The organic matteritself may also be classified as nonporous, spongy or pendular8.

In this study, each area of the 2D SEM produced two im-ages: Secondary electron (SE2) micrographs that are used toquantify porosity and organic matter, and backscattered elec-tron (BSE) micrographs that better display the contrast be-tween the solid components of the rock.

Red Facies

Figure 10a presents examples of such images for the red facies— Sample #1. In this sample, in the SE2 image, the organicmatter appears to be compacted between the delicate clay min-eral layers and elongated in the horizontal direction. This com-paction must have led to the compaction of the pores withinthe organic matter. The BSE image clearly shows the clay min-erals oriented in the horizontal direction due to overbornepressure. The pores in this facies are almost all in the organicmatter, and the porosity value of Sample #1 is around 2% with

only 1% porosity connected in the 3D FIB-SEM volume. Thishas led to a very low matrix permeability of 40 nano-darcy (nD).

Green Facies

Figure 10b presents examples from the green facies — Sample#7. In this sample, in the SE2 image, the organic matter appearsto be protected from severe pressure compaction between thestrong quartz grains and the microcrystalline silica particles.The organic matter in this facies seems to have an irregularshape with a spongy type of porosity at 5%. Therefore, thepore space within the organic matter was preserved and gavegood connectivity in 3D, which yielded a very high permeabilityvalue at 786 nD. The BSE image in Fig. 10b clearly shows thegrainy structure of the quartz particles around the organicmatter that is spread out in the whole image. The pores in thisfacies are almost all in the organic matter.

The poroperm characteristics of these shale facies are plot-ted from the Table 3 data and are shown in Fig. 11. The green

Plug # Core Facies Silica

Pla-gio-clase

K-Feld-spar

Clay Cal-cite

Dolo-mite

Sider-ite

Anhy-drite Pyrite Rutile Apa-

tite Other Total

1 Red 13.7 5.0 0.0 72.1 1.0 0.2 0.0 0.0 4.7 0.5 0.0 2.9 100

2 Red 21.3 5.4 0.3 62.4 0.1 2.5 0.0 0.0 4.7 0.5 0.0 2.8 100

3 Red 25.6 9.8 0.0 44.5 0.0 6.1 0.0 0.0 7.6 0.8 0.2 5.5 100

4 Green 57.5 5.6 0.0 29.1 0.0 1.7 0.0 0.0 3.2 0.3 0.9 1.6 100

5 Green 64.8 2.3 0.0 18.7 0.1 3.9 0.0 0.0 1.3 0.1 0.0 8.8 100

6 Green 74.4 1.6 0.5 20.6 0.1 0.2 0.0 0.0 1.0 0.1 0.0 1.6 100

7 Green 73.0 5.0 0.0 19.1 0.1 0.0 0.0 0.0 1.3 0.4 0.0 1.1 100

8 Green 63.4 4.4 0.0 25.3 0.1 2.1 0.0 0.0 1.3 0.5 0.3 2.7 100

9 Yellow 20.2 8.3 0.0 67.0 0.0 0.0 0.0 0.0 0.5 0.5 0.3 3.1 100

Table 4. Volume percent mineralogy from EDS analysis

Sample Core Facies

Illite/Smectite

Illite+Mica

Kaolin-ite

Chlo-rite Chert Quartz

K Feld-spar

Pla-gio-clase

Cal-cite

Dolo-mite

Sider-ite

Py-rite Total

1 Red 19.9 31.6 15.8 11.2 0.0 10.5 TR 2.1 1.2 1.2 0.0 6.4 100

2 Red 20.2 31.9 12.1 10.0 0.0 12.7 TR 2.9 0.0 1.8 0.0 8.6 100

3 Red 23.9 27.5 0.0 3.5 0.0 21.0 TR 3.6 0.0 2.0 0.0 18.5 100

4 Green 14.8 25.4 0.0 0.2 0.0 42.0 TR 4.2 0.0 4.5 0.0 8.9 100

5 Green 0.0 15.8 0.0 0.0 0.0 76.4 TR 2.3 0.0 1.5 0.0 4.1 100

6 Green 0.4 17.3 0.0 0.0 0.0 74.7 TR 2.8 0.0 1.6 0.0 3.1 100

7 Green 0.2 20.2 0.0 2.6 0.0 69.4 TR 2.0 0.0 0.8 0.0 4.8 100

8 Green 0.2 25.1 0.0 4.0 0.0 58.9 TR 2.3 TR 3.1 2.3 4.0 100

9 Yellow 25.7 35.5 0.0 10.4 0.0 19.3 TR 3.2 0.0 0.0 5.9 0.0 100

Table 5. XRD analysis

for North American shale plays, the data from this MiddleEast shale gas fell within the upper and lower bounds of EagleFord shale in the United States. Figure 12 plots organic mattervs. porosity, both derived from the 3D FIB-SEM volumes, andshows that the red facies have more organic matter with lowerconversion ratios.

EFFECTS OF HETEROGENEITY

Shales are heterogeneous at millimeter to centimeter scales.Figure 13 compares the segmented porosity and organic matterdata from the 2D SEM image with those from the 3D FIB-SEM volume. The figure shows that analyzed samples showporosity variations that could be larger than those of the or-ganic matter at different scales. Porosity estimations from the3D volume could double the initial estimations from the 2DSEM images.

Figure 14 serves as a visual comparison of the 2D and 3DSEM images, where the porosity in this example (Sample #7)decreased from 6.2% in the 2D image to 5.3% in the 3D im-age, and the organic matter decreased from 15.1% in the 2Dimage to 9.2% in the 3D image. The average results from all10 of the 2D SEM images from this sample were 4.8% poros-ity and 13.6% organic matter.

Close inspection of all 10 of the 2D SEM images acquired forevery sample in this study revealed the porosity variation —within each set of the 10 2D SEM images — to be less than 3%porosity unit and the organic matter variation to be less than 5%.

VALIDATION OF CORE FACIES FROM DUAL-ENERGYXCT

The initial plug sample selection in the core was based on accurate application of a dual-energy XCT imaging techniquethat produced continuous BD and PEF data along the corelengths. The sample selection targeted three different facies(green, red and yellow) in the core identified from the

facies samples are at the higher poroperm range. It is interest-ing to note that the red facies samples have higher concentra-tions of the organic matter — 10% to 20% — and yet gavelower poroperm values compared to the green facies sampleswith only 7% to 11% organic matter. These organic matterfigures were derived from the 3D FIB-SEM volumes. In thisperspective, flow properties of this shale formation are con-trolled more by the rock fabric, the mineralogy and the result-ant porosity within the organic matter.

As an initial comparison of these poroperm results to those

Fig. 10. Different pore types detected in different facies.

Fig. 11. Poroperm characteristics of the red and green facies with Eagle Ford upperand lower bounds.

Fig. 12. Organic matter vs. porosity for the red and green facies: The green facieshave larger porosity but less organic matter.


dual-energy CT data. The shale characteristics — porosity, or-ganic matter and mineralogy — of the selected samples fromthe core facies were then confirmed through segmented porosity

and organic matter values derived from high resolution SEMimages and through EDS and XRD analyses. Figure 15 is anice representation of the excellent match in porosity, mineral-ogy and organic matter between core facies described by dual-energy CT and by high resolution SEM images. This wouldassist in more efficient upscaling, improved reserves estimationand enhance well-to-well correlation.

CONCLUSIONS

Initial core facies characteristics — porosity, organic matterand mineralogy — of a shale formation in the Middle Eastwere computed using the dual-energy CT scanning technique.This core facies analysis was used to locate potential sweetspots in the core for optimum sample selection. The selectedplugs, following a well-defined DRP workflow, underwentmultiresolution scanning to construct 3D FIB-SEM volumesfor the determination of shale porosity, organic matter andmineralogy. The objectives of the study were to explore possiblelinks between shale depositional facies and pore types as wellas to quantify the relationship between porosity and matrixpermeability for each identified facies in the core. The objectivesof the study were fulfilled and the following is a summary ofthe key findings in this shale play.1. A robust dual-energy CT scanning technique was used to

characterize a shale gas core and to identify potential facies intervals for DRP analysis.

2. Absolute shale matrix permeability was determined in hori-zontal and vertical directions in 3D FIB-SEM volumes.

3. Only two samples (out of eight) gave 3D connectivity in thevertical direction for permeability simulation in the silica-rich samples. This is consistent with a shale depositional environment and anisotropy considerations.

4. Almost all the porosity was found within the organic mattervolume. Consequently, flow was only possible through organic matter within the 3D volumes.

5. The silica-rich facies gave higher poroperm characteristics

Fig. 13. Comparison between the data obtained from the selected 2D SEM image for 3D FIB-SEM and the 3D volume data: porosity (left) and organic matter (right) —heterogeneity effect.

Fig. 14. Comparison between the data obtained from the selected 2D SEM image(left) from Sample #7 and the 3D FIB-SEM volume (right) — heterogeneity effect.

Fig. 15. Analysis of reservoir shale characteristics (porosity, mineralogy and organicmatter) from core dual-energy CT scanning and SEM.


3. Walls, J. and Armbruster, M.: “Shale Reservoir EvaluationImproved by Dual-energy X-ray CT Imaging: TechnologyUpdate,” Journal of Petroleum Technology, November2012.

4. Amabeoku, M.O., Al-Ghamdi, T.M., Mu, Y. and Toelke,J.: “Evaluation and Application of Digital Rock Physics(DRP) for Special Core Analysis in CarbonateFormations,” IPTC paper 17132, presented at theInternational Petroleum Technology Conference, Beijing,China, March 26-28, 2013.

5. Al-Owihan, H., Al-Wadi, M., Thakur, S., Behbehani, S.,Al-Jabari, N., Dernaika, M., et al.: “Advanced RockCharacterization by Dual-Energy CT Imaging: A NovelMethod for Complex Reservoir Evaluation,” IPTC paper17625, presented at the International PetroleumTechnology Conference, Doha, Qatar, January 20-22, 2014.

6. Al Mansoori, M., Dernaika, M., Singh, M., Al Dayyani, T.,Kalam, Z. and Bhakta, R.: “Application of Digital andConventional Techniques to Study the Effects ofHeterogeneity on Permeability Anisotropy in a ComplexMiddle East Carbonate Reservoir,” SPWLA paper,presented at the SPWLA 55th Annual Logging Symposium,Abu Dhabi, UAE, May 18-22, 2014.

7. Passey, Q.R., Bohacs, K.M., Esch, W.L., Klimentidis, R.and Sinha, S.: “From Oil-Prone Source Rock to GasProducing Shale Reservoir — Geologic and PetrophysicalCharacterization of Unconventional Shale Gas Reservoirs,”SPE paper 131350, presented at the International Oil andGas Conference and Exhibition in China, Beijing, China,June 8-10, 2010.

8. Walls, J.D. and Sinclair, S.W.: “Eagle Ford Shale ReservoirProperties from Digital Rock Physics,” First Break, Vol.29, No. 6, June 2011, pp. 97-101.

9. De Prisco, G., Toelke, J. and Dernaika, M.: “Computationof Relative Permeability Functions in 3D Digital Rocks bya Fractional Flow Approach Using the Lattice BoltzmannMethod,” SCA2012-36 paper, presented at theInternational Symposium of the Society of Core Analysts,Aberdeen, Scotland, U.K., August 27-30, 2012.

10. Mu, Y., Fang, Q., Baldwin, C., Toelke, J., Grader, A., Dernaika, M., et al.: “Drainage and Imbibition Capillary Pressure Curves of Carbonate Reservoir Rocks by Digital Rock Physics,” SCA2012-56 paper, presented at the International Symposium of the Society of Core Analysts, Aberdeen, Scotland, U.K., August 27-30, 2012.

11. Grader, A., Kalam, M.Z., Toelke, J., Mu, Y., Derzhi, N., Baldwin, C., et al.: “A Comparative Study of Digital Rock Physics and Laboratory SCAL Evaluations of Carbonate Cores,” SCA2010-24 paper, presented at the International Symposium of the Society of Core Analysts, Halifax, Nova Scotia, Canada, October 4-7, 2010.

compared to the clay-rich facies. This is due to the pressure compaction effect on the soft clay-rich samples, which caused the organic matter to be squeezed within a clay min-eral framework, leading to closure of the pore space.

6. A very high permeability value (6,000+ nD) was simulated in one of the samples, which a visual examination deter-mined was caused by an unrepresentative porous organic matter layer along the horizontal direction. Such an obser-vation has led to the recognition of the importance of the visuals in explaining the petrophysical data in the samples.

7. A higher percentage of organic matter was not found to be a good indication for high porosity or permeability in the clay-rich shale samples in this study. The conversion ratios of organic matter should be taken into consideration when judging porosity or permeability.

8. A clear trend was observed between porosity and perme-ability in relation with the identified facies in the core.

9. The depositional facies was found to have a great effect on the pore types, rock fabric and reservoir properties. Of par-ticular importance are the mineralogy and clay in the samples.

10. Shale heterogeneity in this formation showed larger effectson porosity variability than organic matter variations at different scales.

11. The results and interpretations in this study enhanced our understanding of the complexity of unconventional shalereservoir quality.

NOMENCLATURE

K permeabilityKh horizontal permeabilityKv vertical permeabilityZeff effective atomic numberØ porosity

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this article.Ingrain Inc. conducted the measurements discussed in this article.

This article was presented at the SPE-SAS Annual TechnicalSymposium and Exhibition, al-Khobar, Saudi Arabia, April 21-24, 2014.

REFERENCES

1. Butler, J.A., Bryant, J.E. and Allison, D.B.: “HydrocarbonRecovery Boosted by Enhanced Fracturing Technique,”SPE paper 167182, presented at the SPE UnconventionalResources Conference-Canada, Calgary, Alberta, Canada,November 5-7, 2013.

2. Wellington, S.L. and Vinegar, H.J.: “X-ray ComputerizedTomography,” Journal of Petroleum Technology, Vol. 39,No. 8, 1987, pp. 885-898.


12. Tolke, J., Baldwin, C., Mu, Y., Derzhi, N., Fang, Q., Grader, A., et al.: “Computer Simulations of Fluid Flow in Sediment: From Images to Permeability,” The Leading Edge, Vol. 29, No. 1, January 2010, pp. 68-74.

13. Loucks, R.G., Reed, R.M., Ruppel, S.C. and Hammes, U.: “Preliminary Classification of Matrix Pores in Mudrocks,” Gulf Coast Association of Geological Societies Transactions, Vol. 60, April 2010, pp. 435-441.

BIOGRAPHIES

Anas M. Al-Marzouq is a PetroleumEngineer in Saudi Aramco’s ReservoirDescription Division. He joined SaudiAramco in 2004 and is currentlyworking in the ExplorationPetrophysical Unit. Anas is a memberof the Tight Gas Assessment team, the

Unconventional Gas Petrophysical team and the NorthwestUnconventional Gas Operation team.

He has published and coauthored many papers andjournal articles. Anas’s recent work involves integration ofthe core and petrophysical measurements to evaluateunconventional gas resources.

He received his B.S. degree from King Fahd Universityof Petroleum and Minerals (KFUPM), Dhahran, SaudiArabia, in 2004, and his M.S. degree from Texas A&MUniversity, College Station, TX, in 2010, both in PetroleumEngineering.

Dr. Tariq M. Al-Ghamdi is a ReservoirEngineer working in Saudi Aramco’sReservoir Description and SimulationDepartment. His responsibilitiesinclude management and petrophysicalevaluation of exploration and gasfields. Tariq is currently leading the

Unconventional Shale Gas team in Saudi Aramco. His maininterests are optimizing petrophysical evaluation,permeability modeling and modeling saturation heightfunction; recently Tariq has been involved in digital coreanalysis and numerical simulations of special core analysisand nuclear magnetic resonance. He has published andcoauthored numerous papers and journals.

Tariq received his B.S. degree from the University ofTulsa, Tulsa, OK, his M.S. degree from Heriot-WattUniversity, Edinburgh, U.K., and his Ph.D. degree from theUniversity of New South Wales, Kensington NSW,Australia, all in Petroleum Engineering.

Unconventional Shal

Unconventional Gas

Safouh Koronfol joined Ingrain Inc. inMay 2012 and is the OperationsManager. He has 10 years of specialcore analysis experience. Safouh wasthe Head of the Special Core AnalysisDepartment at WeatherfordLaboratories Abu Dhabi and later

became the SCAL coordinator between Weatherford Labsglobally and Shell/Petroleum Development Oman inMuscat, Oman.

Safouh received his B.S. degree in Industrial Chemistryfrom University of Aleppo, Aleppo, Syria. He is an activemember of Society of Petrophysicists and Well LogAnalysts (SPWLA), the Society of Petroleum Engineers(SPE) and the Society of Core Analysts (SCA). Safouh hasauthored and coauthored seven technical papers on bothconventional SCAL and digital rock physics.

Dr. Moustafa R. Dernaika has beenthe Manager of Ingrain Inc. AbuDhabi since 2010. Before he joinedIngrain, he worked for Emirates LinkResLab LLC (WeatherfordLaboratories) as the Regional SpecialCore Analysis (SCAL) Manager in Abu

Dhabi. He has 15 years of routine and SCAL experiencewith special interest in business development, projectmanagement and data interpretation.

Moustafa has written 26 technical papers. His currentresearch areas include digital rock physics, dual energycoiled tubing applications and the variations ofpetrophysical and flow properties with rock types andwettability.

Moustafa received his B.S. and M.S. degrees inChemical Engineering from the Middle East TechnicalUniversity, Ankara, Turkey, and his Ph.D. degree inPetroleum Reservoir Engineering from the University ofStavanger, Stavanger, Norway.

Dr. Joel D. Walls is a Geophysicistfocused on research, development, andcommercialization of advanced digitalrock physics services for unconventionalreservoirs. He joined Ingrain Inc. in2010, and as the Director of Technology,Joel guides the development and

commercialization of services focused on shale plays. Joel was a co-founder and the first president of the

Society of Core Analysts (SCA). He is a member of theSociety of Economic Geologists (SEG), Society of PetroleumEngineers (SPE) and the Society of Petrophysicists and WellLog Analysts (SPWLA). Joel is the author of numerouspublications in several geophysical and petrophysicaljournals, and holds four U.S. patents in the rock physicsand reservoir characterization.

He received his B.S. degree in Physics from Texas A&MUniversity, College Station, TX. Joel received his M.S. andPh.D. degrees in Geophysics from Stanford University,Stanford, CA.

b h SCAL

Dh bi H h 15

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ABSTRACT fracture. The results were very encouraging, and the generatedhigh-pressure/high temperature caused the gel to break. There-fore, it was concluded that this technique effectively contributesto fracture cleanup in addition to creating the required SRV.The experiments were very successful in proving the new con-cept for generating SRV in a tight gas well, and the developedstimulation technique is fairly easy to implement in the field.

INTRODUCTION

There is tremendous potential for tight gas plays to providelong-term energy throughout the world because of the vast resource base that these formations represent. Horizontaldrilling and multistage hydraulic fracturing technologies haveallowed significant gas to be produced from shale gas and tightsand formations. Yet the primary recovery factors have been lessthan 20%, which implies the compelling need for advancedtechnologies. The goal of this research effort is to provide acost-effective stimulation technique that potentially replacescostly multistage hydraulic fracturing in shale gas and tightsand formations.

Water scarcity in the Kingdom requires a new look at frac-turing treatments. Energized and waterless fracturing is anevolving and promising technology that eliminates the polymerresidue within the created fracture and the water phase trappingwithin the rock matrix — both of these damaging mechanismsare associated with conventional water-based fracturing stimu-lation of tight gas wells. Additionally, the conventional fracturingmust be carefully applied to stimulate tight gas plays because itis not the single, conductive, and long fracture that one is after;rather what one wants is the stimulated volume connected tothe well, needed to make it a commercial producer. The currentcostly multistage fracturing is helping, but there is a desperateneed for cost-effective stimulation techniques. New alternativesto hydraulic fracturing are being researched, including tailoredgas fracturing, with the ultimate objective of replacing the current costly fracturing with a more cost-effective and envi-ronmentally friendly treatment that could significantly reducestimulation costs.

Several articles have been presented on introducing a pres-sure pulse loading into a given well to induce near wellborefracture1-3. The technique is based on loading a well with a

The huge resources of unconventional gas worldwide, alongwith the increasing oil demand, make the contribution of un-conventional gas critical to the world economy; however, one ofthe major challenges that operators face with production fromunconventional resources is finding a commercial stimulationtechnique that creates sufficient stimulated reservoir volume(SRV). Unconventional reserves trapped within very low per-meability formations, such as tight gas or shale formations, exhibit little or no production, and are therefore economicallyundesirable to develop with existing conventional recoverymethods. Such reservoirs require a large fracture network withhigh fracture conductivity to maximize well performance.

One commonly employed technique for stimulating lowproductivity wells is multistage hydraulic fracturing, which iscostly and typically involves the injection of high viscosity flu-ids into the well. Fracturing fluid by itself could be a damagingmaterial for the fracture due to the high capillary forces in-volved. Therefore, the need exists for another more economicalmethod to enhance production within a tight gas formation.

This article discusses a new stimulation method to increaseSRV around the wellbore and fracture area, thereby improvingunconventional gas production. The method entails triggeringan exothermic chemical reaction in situ to generate heat, gasand localized pressure sufficient to create fractures around thewellbore. In a controlled experiment, chemical reactants wereseparately injected into core samples with a mini-hole, andupon their mixing inside the core, an exothermic chemical re-action occurred and the resultant heat and gas pressure causedmacrofractures. Nuclear magnetic resonance (NMR) porosityimaging showed a significant increase in macropores through-out the core. Additionally, large-scale experiments using cementblocks with a simulated wellbore cavity were performed. Oncethe wellbore was filled with the chemicals and a triggering cat-alyst was introduced, an in situ chemical reaction took place,which generated heat and gas with sufficient pressure to causeshear fractures in the surrounding rock. These experiments, whichshowed extensive fractured and shattered pieces, also providedpreliminary design requirements for a field test. The chemicalreactants were then incorporated into a fracturing gel that sim-ulated additional fractures created from the main induced hydraulic

Chemically Induced Pressure Pulse:A Novel Fracturing Technology ForUnconventional Reservoirs

Authors: Ayman R. Al-Nakhli, Dr. Hazim H. Abass, Mirajuddin R. Khan, Victor V. Hilab, Ahmed N. Rizq andAhmed S. Al-Otaibi


high-pressure pulse over a short period of time so that thepressure exceeds all in situ stresses, causing multiple fractures topropagate in all directions. The fast expanding pulse generatesstress waves, which travel through the rock medium, creatingfractures in the reservoir. A new technique discussed in this ar-ticle is based on generating a pressure pulse but via an in situexothermic chemical reaction.

The pressurization time is the main parameter that deter-mines the fracture pattern. The number of fractures initiatedincreases with an increase in loading rate, for loading ratesabove the onset pressure. There are three main categories offracturing techniques. First is hydraulic fracturing, with thelongest pressure rise time (P ≤ 1 MPa/s), which creates a singleradial fracture. A second technique is using explosives downhole,which has the shortest rise time (P ≥ 107 Mpa/s) and generatescompacted zones with multiple radial fractures. The third tech-nique is using propellant to generate multiple radial fractures,which has an intermediate pressure rise time (p ≈ 102 MPa/s ~106 MPa/s). In general, the number of fractures initiated in-creases with an increase in pressurizing rate for the intermedi-ate pressurizing rate techniques1-3.

Controlling the pressurizing rate is a key factor for control-ling the fracture pattern. The new invention describes a newrock fracturing technique, which has significant advantagesover the three methods just described. With this novel invention,pressurizing time can be controlled, so a fracturing pattern canalso be optimized1.

The damaging effect of the fracturing technique is another keyfactor considered during the fracturing selection process. Deto-nating an explosive in a wellbore generally creates a damagedzone surrounding the wellbore wall that impairs permeabilityand communication with the reservoir. The pressurization rateis very high, which causes compressive stresses in the wellborearea that are much higher than the in situ stress state. Thisstress environment can cause compaction or pulverization of afinite zone around the wellbore to such a degree that perme-ability is decreased significantly.

CONCEPT

Unconventional gas requires an extensive fracturing network tocreate commercially producing wells. One commonly employedtechnique is multistage hydraulic fracturing in horizontal wells,which is very costly and may not provide the required stimu-lated reservoir volume (SRV). Therefore, a need exists for aneconomical method to enhance production within tight gas for-mations. A new technique has been developed to increase SRVaround the wellbore and fracture area, and therefore improveunconventional gas production. The method entails triggeringan exothermic chemical reaction in situ to generate heat, gasand localized pressure sufficient to create fractures around thewellbore.

In a controlled experiment, chemical reactants were sepa-rately injected into core samples with a mini-hole, and upon

their mixing inside the core, an exothermic chemical reactionoccurred and the resultant heat and gas pressure causedmacrofractures. Nuclear magnetic resonance (NMR) porosityimaging showed a significant increase in macropores throughoutthe core. Additionally, large-scale experiments using cementblocks with a simulated wellbore cavity were performed. Oncethe wellbore was filled with the chemicals and a triggering cat-alyst was introduced, an in situ chemical reaction took place,which generated heat and gas with sufficient pressure to causeshear fractures in the surrounding rock. These experiments,which showed extensive fractured and shattered pieces, alsoprovided preliminary design requirements for a field test. Thechemical reactants were then incorporated into a fracturing gelthat simulated additional fractures created from the main in-duced hydraulic fracture. The results were very encouraging,and the generated high-pressure/high temperature (HPHT)caused the gel to break. Therefore, it was concluded that thistechnique effectively contributes to fracture cleanup in addi-tion to creating the required SRV. The experiments were verysuccessful in proving the new concept of generating SRV intight gas wells, and the developed stimulation technique isfairly easy to implement in the field.

AUTOCLAVE REACTOR TESTING

Two autoclave reactors, Fig. 1, were used to study the reactionkinetics of the selected chemicals. One system was rated up to10,000 psi and 500 °C with a total volume of 3 liters, and theother was rated up to 20,000 psi. Experiments were carriedout in a dedicated specialized HPHT laboratory equipped withthe required safety features. The experimental parameters werecontrolled and PC monitored remotely. Real-time pressure andtemperature data were recorded every 2 seconds to observe theresulting pressure-temperature behavior during the chemicalreaction. This testing phase was performed to simulate thepressure and temperature anticipated to occur in a given well-bore as a result of injecting the chemicals and triggering the reaction. There was one critical assumption; that the well isdrilled in a zero permeability formation to match that of theautoclave reactor. Although this is not a practical assumption,


Fig. 1. Autoclave systems rated up to 10,000 psi and 20,000 psi.

it is an approximation of the extremely low permeability whena well is drilled in a shale formation. There were two inde-pendent variables considered in these tests; the molarity of thechemicals, and the initial pressure and ratio of the chemical’svolume to the autoclave reactor vessel’s volume.

ENVIRONMENTAL SCANNING ELECTRON MICROSCOPY (ESEM)

The rock samples were examined in the environmental scanningelectron microscope (ESEM) with an integrated energy disper-sive X-ray system. The ESEM equipment was operated at 15kV, 0.4 Torr water vapor pressure and around 8 mm workingdistance. Useful and insightful textural information on the twoformations was obtained by acquiring surface images from dif-ferent parts of the examined samples. The samples were mountedon ESEM holders using double-sided carbon tape, and then thesamples were inserted into the ESEM chamber for analysis.

MR-CT MICROSCOPE

A magnetic resonance and computed tomography (MR-CT)microscope is a new suite of core analysis tools that utilizesNMR combined with X-ray CT to improve the description ofpore property changes as a result of coreflooding with differenttypes of fluids4. The MR-CT microscope allows the observa-tion of microscopic events within reservoir porous media andprovides fluid-rock interaction with proper mineralogy quan-tification information. Both a medical CT scan and a micro CTscan were also used to evaluate the chemical treatment on thecarbonate cores.

ROCK BLOCK TESTING

A series of laboratory experiments were conducted to provideinsight on applying the concept of chemically induced pulsefracturing in the field. Rock samples used in these experimentswere rectangular blocks with dimensions of 8” x 8” x 8” and10” x 10” x 10”. Each rock sample was made to have a 1½” x3” cavity to simulate a wellbore. The tested rocks were Indianalimestone, Berea sandstone, shale and cement. The man-maderock samples were cast by mixing water and cement with aweight ratio of 31/100, respectively.

The physical and mechanical properties of the rock sampleswere: porosity = 29%, bulk density = 1.82 gm/cc, Young’smodulus = 1.92 x 106 psi, Poisson’s ratio = 0.26, uniaxialcompressive strength = 3,299 psi, cohesive strength = 988 psiand internal friction angle = 28°. The breakdown pressure forthis test was 5,400 psi.

A vertical open hole was cast or drilled in the center of theblock. For the unconfined test, the simulated wellbore was 3”long and 1½” in diameter, Fig. 2. For the confined test, the vertical open hole was cast all the way through the center ofthe block, Fig. 3. The exothermic chemicals were used with a

fracturing gel. The fracturing gel was water-based WG-17,with a loading of 40 lb/Mgal. The viscosity of this fluid wasabout 1,600 centipoise (cP) at a share rate of 81 s-1 at roomtemperature. The concentrations of the exothermic chemicalsvaried from 3 molar to 5 molar and were used immediately af-ter preparation. The injection rate was about 30 cc/min to 100cc/min.

Samples were tested with and without confinement. For theconfined stress testing, samples were loaded in a biaxial cellwith equal horizontal stresses of 2,000 psi for one test and4,000 psi for another test. If we consider a well depth of 2,570ft, these stresses represent gradients of 0.78 psi/ft and 1.56


Fig. 2. Block design for unconfined tests.

Fig. 3. Block design for confined tests.

psi/ft, respectively. The reactive chemicals were injected in theblock and heat was applied using the biaxial plates.

UNCONFINED CONDITION TESTING

Tests 1 and 2

The samples for this type of test, which simulated an open holevertical well, were man-made cement blocks. The rock sampleswere preheated to 200 °F. Then reactive chemicals were injectedin the rock at atmospheric pressure and at a rate of 15 cc/min.As chemical injection was completed and the reaction tookplace, multiple fractures were created, as shown in Figs. 4 and5. The created fractures were longitudinal and perpendicularwith respect to the vertical wellbore. The fracture geometry in-dicates that fractures propagated from the wellbore to the endof the sample. This indicates that the pressure generated wasgreater than the compressive strengths of the samples. Thebreakdown pressure for these tests was 5,400 psi.

Test 3

The Indiana limestone block sample was used for this test witha drilled hole 3” long and 1½” in diameter, to simulate a verti-cal open hole well. The block was preheated to 200 °F, then reactive chemicals were injected in the rock at atmosphericpressure and at a rate of 15 cc/min. As chemical injection wascompleted and the reaction took place, multiple fractures werecreated within two minutes, Fig. 6. The created fractures weretwo longitudinal and one perpendicular with respect to the ver-tical wellbore. The breakdown pressure for this test was 4,700psi. The physical and mechanical properties of the Indianalimestone rock samples were: porosity = 28%, bulk density =

1.82 gm/cc, Young’s modulus = 1.92 x 106 psi, Poisson’s ratio= 0.26, uniaxial compressive strength = 3,299 psi, tensilestrength = 271 psi, cohesive strength = 1,067 psi and internalfriction angle = 23°.

Test 4

A shale block sample from Mancos was used for this test witha drilled hole 2” long and 1½” in diameter, to simulate a verti-cal open hole well. In this test, the reactive chemicals were in-jected first, then the block was placed in a 200 °F oven. After 3hours, a chemical reaction took place and multiple fractureswere created, Fig. 7. The time interval for the reaction to beactivated simulated the downhole temperature recovery of thewellbore. The breakdown pressure for this test was 6,600 psi.The physical and mechanical properties of the shale rock sam-ples were: porosity = 3.8%, bulk density = 2.50 gm/cc, Young’smodulus = 2.66 x 106 psi, Poisson’s ratio = 0.20, uniaxial com-pressive strength = 4,965 psi, cohesive strength = 1,268 psi andinternal friction angle = 36°.

CONFINED CONDITION TESTING

Samples for this test simulated a vertical open hole well with ahole drilled in the center of an 8” x 8” x 8” cube, Fig. 8. Thehole was 1½” in diameter, extending throughout the wholelength of the sample, as previously shown in Fig. 3. The testsample was then placed in a biaxial loading frame where twohorizontal stresses of a given stress were applied while the vertical stress was controlled by mechanical tightening of the


Fig. 4. Pre- and post-treatment views of white cement block sample, usingchemically pulsed fracturing.

Fig. 5. Pre- and post-treatment views of portrait cement block sample, usingchemically pulsed fracturing.

Fig. 6. Pre- and post-treatment views of Indiana limestone block sample, usingchemically pulsed fracturing.

Fig. 7. Pre- and post-treatment views of shale block sample, using chemicallypulsed fracturing.

base and top platens, Fig. 9. Then reactive chemicals were in-jected in the rock at atmospheric pressure and room temperatureat a rate of 15 cc/min. The sample was then heated for 2 to 3hours until the reaction took place and fractures were created.Two tests were performed as follows.

Test 5 and 6

For Test 5, the applied horizontal stress was 2,000 psi at bothdirections, Fig. 10. The reaction was triggered at 167 °F. Upontriggering the reaction, three longitudinal and one perpendicu-lar fractures were created with respect to the vertical hole, Fig.11. The applied horizontal stress in Test 6 was 4,000 psi atboth directions, Fig. 12. Almost the same behavior was ob-served for this test. Four longitudinal fractures were createdwith respect to the vertical hole, Fig. 13. The fracture geometryshows that the created fracture was longitudinal with respectto the vertical wellbore. The fracture geometry indicates thattwo sets of fractures propagated from the wellbore to the endof the sample. This indicates that the pressure generated wasgreater than 8,000 psi. Each created planar fracture propagatedin the direction of one σH and perpendicular to the directionof the other σH, as the applied stress is equal in both horizontaldirections.

REACTOR TESTING

An autoclave reactor, rated up to 10,000 psi, was used to testthe chemical reaction. Figure 14 shows a typical reaction behavior with pressure and temperature pulses. In this test,

reactive chemicals were placed in the autoclave at room condi-tions. Then the temperature was increased until reaction wastriggered at 120 °F. The pressure rise time was less than 2 sec-onds, which is the machine’s low limit. So, depending on thepressurizing rate, multiple fractures were expected to be gener-ated in the rock samples.

The initial pressure does not have a negative impact on the


Fig. 8. 8” x 8” x 8” cement block.

Fig. 9. Biaxial system for confined condition tests.

Fig. 10. Pulsed fracturing under 2,000 psi biaxial stress.

generated pressure pulse. As can be seen in Fig. 15, the finalpressure is a function of the initial pressure. In other words, final pressure is the summation of initial reactor pressure andreaction generated pressure; however, the temperature was almost constant with the changes in initial pressure at fixedchemical concentration and volume.

In another test, reactive chemicals were prepared with cross-linked fracturing gel (40 lb/1,000 gal), Fig. 16. The solution’spH was adjusted to 9.7. Then the gel was injected into the reactor, which was preset at 200 °F. The reaction was not trig-gered for 1 hour, not until the gel breaker was injected. When thegel breaker was injected, which reduces the solution pH, thepressure pulse was generated. This characteristic can give morecontrol over the reaction behavior for field applications.

EFFECT OF CONCENTRATION AND VOLUME

The chemicals were tested using an autoclave at different con-centrations and solution volumes. The results showed thatpressure is a function of chemical concentration and volume.The greater the solution volume used, the greater the generatedpressure, Fig. 17. At 50 vol%, the pressure increased from 988psi to 6,100 psi and then to 16,600 psi, as the concentration


Fig. 11. Fractured cement block under 2,000 psi biaxial stress.

Fig. 12. Pulsed fracturing under 4,000 psi confined stress.

Fig. 13. Fractured cement block under 4,000 psi biaxial stress.

Fig. 14. Chemical reaction at zero psi initial pressure and 2X solution volume.

Fig. 15. Chemical reaction at different initial pressure.

Fig. 16. Activation of cross-linked gel containing reactive chemicals using a breaker.

was increased from 1x to 3x and then to 4x, respectively.These are actual data measured using the autoclave system.Tests also showed that the greater the concentration, thehigher the generated pressure was. As the solution volume wasincreased from 50 vol% to 100 vol%, the generated pressurethat was measured increased from 988 psi to 20,000 psi. It isanticipated that the pressure can exceed 45,000 psi usingchemicals at high concentrations and large volumes.

TRIGGERING TEMPERATURE

Figure 18 shows that the reaction triggering temperature wasaround 200 °F at zero initial reactor pressure and a 6.5 pH solution. Once this temperature was reached, the reaction progressed vigorously and reached maximum pressure andtemperature in milliseconds. The minimum limit of the auto-clave system was 2 seconds, so it was not possible to recordthe reaction pulse duration. During experiments with an initialreactor pressure of 350 psi and higher, the triggering tempera-ture was stabilized round 122 °F. When the solution pH wasincreased from 6 to 9, the triggering temperature increasedfrom 200 °F to 230 °F, at zero initial pressure. At an initial

pressure of 500 psi, the triggering temperature was increasedfrom 122 °F to 184 °F, as the pH increased from 6.5 to 9.

SYNTHETIC SWEET SPOT

Microscopic analysis of a sample treated with the reactivechemicals showed that no damaged zone was formed aroundthe treated area; however, a synthetic sweet spot was created,Figs. 19 and 20. A tight core sample with an air permeabilityof 0.005 nano-darcy was chemically treated using the core-flood system. The chemical was injected through a drilled holewithin the core sample, two-thirds of the total core samplelength, 3.2”. The core diameter was 1½” with porosity of1.35%. Pre- and post-treatment CT scan analysis shows signif-icant density reduction, also seen in Figs. 19 and 20. Voids arescattered around the treated area throughout the core sample.The change in slice colors from red and green to green andblue indicates a reduction around the treated area, which re-flects an increase in porosity. ESEM analysis shows that mi-crofractures were created along the core sample. The MR-CTmicroscope image also shows visible voids and high porosityaround the treated hole, Fig. 20, which was confirmed byESEM analysis. Several backscattered electron topographical


Fig. 17. Effect of chemical concentration and volume on pressure pulse.

Fig. 18. Reaction triggering temperature behavior.

Fig. 19. Pre-treatment tight core sample (MR-CT, ESEM and CT scan).

Fig. 20. Post-treatment tight core sample with synthetic sweet spot, (MR-CT,ESEM and CT scan).


images were taken at different magnifications from differentparts of the samples, but mainly from the center of the rocksamples. The acquired images show submicron pores and micro-cracks. The sizes of the pores were measured and found to bein the range of less than 1 micron to 50 microns. The concen-tration of the cracks and pores was mainly in the center of therock, where the epicenter of the treatment took place. Theexothermic reaction treatment thereby led to the initiation ofmicro-cracks and pores in the rock samples4, 5.

MR-CT MICROSCOPE

The pre- and post-treatment MR-CT microscope results showa significant increase in macropores throughout the core andsuggest communication among an otherwise isolated system ofmicro-, miso- and macropores of the core, with an overall per-meability increase. Figure 20 also shows the isolated porositysystem of the pre-treatment core sample, where the micro-,miso- and macropores are clearly not communicating witheach other; however, post-treatment results show strong com-munication among all pore sizes6.

CT-SCAN OF RM9 AND RM13

The pre- and post-treatment medical CT scan images of thetreated core samples show a significant porosity increase andnumerous created fractures due to the chemical reaction, previ-ously seen in Figs. 19 and 20. The red color represents highdensity and low porosity sites, while the blue color represents alow density and high porosity system. Pre- and post-treatmentimages of a tight core sample show the creation of fracturesperpendicular to the flow of injection. A clear reduction ofdensity and porosity is noted. Fractures and voids are clearlyshown in black in both samples.

VISCOSITY AND COMPATIBILITY WITH FRACTURINGFLUID

The reactive chemicals were prepared and showed compatibilitywith the cross-linked fracturing fluid, Fig. 21. The gel, contain-ing reactive chemicals, was also prepared with proppant andagain showed compatibility, Fig. 22. The gel was activated inthe autoclave system by heating to the triggering temperature.The heat generated by the reaction broke the gel viscosity, evenwithout injecting the gel breaker, Fig. 23. Therefore, this typeof treatment can help clean up the well after a fracturing job.Using a Chandler viscometer, the viscosity of the cross-linkedgel, containing reactive chemicals, was measured pre- andpost-reaction. The gel viscosity was reduced from 1,600 cP to10 cP, Fig. 24. This indicates the reactive chemicals can fullybreak the gel viscosity, which can help in fracture cleanup.

Fig. 21. Reactive gel with proppant.

Fig. 22. Pre-reaction gel.

REACTION ACTIVATION METHOD FOR FIELD APPLICATION

Injecting a preflush reduced the downhole temperature from250 °F to 100 °F, Fig. 25. The cooling effect and heat recoveryof the treated well can be used to self-activate the reactivechemicals. By selecting the optimum pH, the reactive chemicalscan take from 1 to 3 hours to be activated, depending on thedesigned procedures and required need. From Fig. 25, resultsshow it took around 4 hours for the downhole temperature toreach 184 °F, which is the triggering temperature of the reactivechemicals using a 9 pH solution. This gives sufficient time toplace and self-activate the gel downhole.

CONCLUSIONS

1. A new shale or tight gas stimulation technique has beendeveloped using chemical reaction and has been proventhrough laboratory experiments. This new approach isbased on pulsed fracturing.

2. Multiple fractures were created using the new technique inshale, Indiana limestone, Berea sandstone and cementblock samples. Fracturing was also tested, using cement


block samples, under a stress level of 4,000 psi.

3. This technique can be used to increase SRV in shale ortight gas wells. The technology can also be applied tostimulate limestone and sandstone formations.

4. The simplicity of this technique makes it very attractive toimplement. The applicability of this technique has beendemonstrated in the laboratory and a field trial is beingplanned. There is no special tool required to apply thetechnology in the field, compared to propellant techniques.

5. The reactive chemicals are compatible with the fracturingfluid and can be activated by either reservoir thermal effector pH reduction.

6. A synthetic sweet spot is created around the treated area oftight rock samples using the new chemical treatmentmethod. This confirms that no damaged zone will beformed.

7. The new technology can enable fracture cleanup.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this article.

Fig. 23. Post-reaction gel.

Fig. 25. Cooling effect of preflush on downhole temperature.

Fig. 24. Reaction effect on breaking cross-linked gel viscosity.


This article was presented at the Unconventional ResourcesTechnology Conference, Denver, Colorado, August 25-27, 2014.

REFERENCES

1. Swift, R.P. and Kusubov, A.S.: “Multiple Fracturing ofBoreholes by Using Tailored-Pulse Loading,” Society ofPetroleum Engineers, Vol. 22, No. 6, 1982, pp. 923-932.

2. Cuderman, J.F.: “Tailored-Pulse Fracturing in Cased andPerforated Boreholes,” SPE paper 15253, presented at theSPE Unconventional Gas Technology Symposium,Louisville, Kentucky, May 18-21, 1986.

3. Yang, D.W. and Risnes, R.: “Experimental Study onFracture Initiation by Pressure Pulses,” SPE paper 63035,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, October 1-4, 2000.

4. Al-Nakhli, A.R., Abass, H.H., Kwak, H.T., Al-Badairy, H.,Al-Ajwad, H.A., Al-Harith, A., et al.: “OvercomingUnconventional Gas Challenges by Creating SyntheticSweet Spot and Increasing Drainage Area,” SPE paper164165, presented at the SPE Middle East Oil and GasShow and Conference, Manama, Bahrain, March 10-13,2013.

5. Al-Ajwad, H.A., Abass, H.H., Al-Nakhli, A.R., Al-Harith,A.M. and Kwak, H.T.: “Unconventional Gas Stimulationby Creating Synthetic Sweet Spot,” SPE paper 163996,presented at the SPE Unconventional Gas Conference andExhibition, Muscat, Oman, January 28-30, 2013.

6. Kwak, H.T., Funk, J.J., Yousef, A.A. and Balcom, B.J.:“New Insights into Microscopic Fluid/Rock Interaction:MR-CT Microscopy Approach,” SPE paper 159194,presented at the SPE Annual Technical Conference andExhibition, San Antonio, Texas, October 8-10, 2012.

BIOGRAPHIES

Ayman R. Al-Nakhli is a PetroleumScientist with the ProductionTechnology team of Saudi Aramco’sExploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC),where he is involved in the study of

unconventional reservoirs. His main research interest isdeveloping new technologies in the field of fracturing,stimulation, heavy oil recovery, unconventional gas andsmart fluids. Ayman has generated several patents andpublished several papers related to production technology.He has also published a book about self-development.

He received his B.S. degree in Industrial Chemistry fromKing Fahd University of Petroleum and Minerals (KFUPM),Dhahran, Saudi Arabia, and an MBA from OpenUniversity Malaysia, Bahrain.

unconventional reserv

Dr. Hazim H. Abass was a SeniorConsultant at Saudi Aramco’sExploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC). Hehas advanced the geomechanicsdiscipline by developing practical

applications to solve petroleum related problems. Hazimhas pioneered advanced techniques related to orientedperforation, fracturing horizontal wells, acid fractureclosure, sanding tendency, gas hydrate and water coning.

Before joining Saudi Aramco in 2001, he worked for theNorthern Petroleum Organization in Iraq, the HalliburtonResearch Center in Oklahoma and the PDVSA ResearchCenter in Venezuela.

Hazim is the recipient of the 2008 SPE Middle EastRegional Award, Production Operations; the 2009 SPEInternational Award, Distinguished Member; the 2012 SPEInternational Award, Completion Optimizations andTechnology; and the 2012 SPE Middle East RegionalAward, Completion Optimizations and Technology. He wasone of the SPE Distinguished Lecturers for the 2011/2012season, educating professionals around the globe on “theuse and misuse of applied rock mechanics in petroleumengineering.”

Hazim holds 10 U.S. patents, has authored more than40 technical papers and contributed to three industrialbooks. He is a member of the Society of PetroleumEngineers (SPE) and the Technical Editor of its journalProduction & Facilities, and he is a member of theInternational Society for Rock Mechanics (ISRM).

In 1977, Hazim received his B.S. degree in PetroleumEngineering from the University of Baghdad, Baghdad,Iraq. He received his M.S. and Ph.D. degrees in 1987 inPetroleum Engineering from the Colorado School of Mines,Golden, CO.

He retired from Saudi Aramco in September 2014.

Mirajuddin R. Khan joined SaudiAramco in 1991. He is a Geologistworking in Saudi Aramco’sExploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC). Hisinterests are rock mechanics’

applications in petroleum engineering. Mirajuddin is amember of the Society of Petroleum Engineers (SPE) andhas published several technical papers.

Before joining Saudi Aramco, Mirajuddin worked as aTeaching Assistant for 1 year and then received ascholarship to work as a Research Scholar for 2 years atthe University of Karachi.

His awards include the 2004 Recognition Award of theEngineering & Operations Services of Saudi Aramco.

Mirajuddin received his B.S. degree in 1984 and hisM.S. degree in 1985, both in Petroleum Geology from theUniversity of Karachi, Karachi, Pakistan.

li i l

applications in petro

Victor V. Hilab is a PetroleumEngineer with the ProductionTechnology team of Saudi Aramco’sExploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC). Hehas 36 years of experience working in

chemistry laboratories, of which 26 years has been withSaudi Aramco. Victor’s areas of interest are research information damage analysis and remediation, scaleproblems, wastewater disposal, and injection water qualityand fracturing. He is currently working in laser and heavyoil research.

Victor is a member of the Society of PetroleumEngineers (SPE) and the American Chemical Society (ACS).He has authored and coauthored many papers throughouthis career. Victor also has one granted U.S. patent.

He received his B.S. degree in Chemical Engineeringfrom FEATI University, Manila, Philippines.

Ahmed N. Rizq is a Lab Technicianwith the Production Technology teamof Saudi Aramco’s Exploration andPetroleum Engineering Center –Advanced Research Center (EXPECARC). He has several years ofexperience, working with the

Geochemistry Division for 3 years, the R&D Division for 1year and the Geology Technology team for 2 years.Ahmed’s interests include unconventional resources andreducing the cost of production.

He received his B.S. degree in Chemical Engineeringfrom Jubail Industrial University, Jubail, Saudi Arabia.

Ahmed S. Al-Otaibi joined theIndustrial Training Center in 2008, fora 2 year program. He then went on tostudy at Jubail Industrial College for10 months, graduating in July 2011.Ahmed then joined Saudi Aramco as aLab Technician with the Production

Technology Team of Saudi Aramco’s Exploration andPetroleum Engineering Center –Advanced Research Center(EXPEC ARC).

Geochemistry Divisio

TeT chnology TeT am of

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ABSTRACT systems has been developed to measure, capture, store,process, manage and visualize massive amounts of data forreal-time decision making2, 3. The boundary of the technology isalways being pushed to get systems to provide more subsurfacemulti-station, multivariable, multiphase real-time measurementsalong a wellbore. The availability of such large amounts ofcomplex data has been a challenge for the industry to handle,and companies are developing a growing number of applicationsto transform this data into useful information. Al-Mulhim et al.(2010)4 and AbdulKarim et al. (2010)1 both described the application of intelligent field data in the area of real-time con-trol in oil and gas field operations. Yuen et al. (2011)5 describedintelligent field data as one of the four major evolving techno-logical developments influencing advanced reservoir simulationpractices in the oil and gas industry; the other three are highresolution geological modeling, Thomeer pore description andhigh performance computing clusters.

High resolution reservoir modeling attempts to capture sig-nificant heterogeneities on a small physical scale. The high resolution temporal data generated by intelligent field operationscapture pressure responses on a small time scale, yet in reservoirsimulation practice, reservoir engineers are often encouragedto use algorithms that enable simulators to take large timesteps during the computation to reduce computing time and resources. This is even more so the case with models that arespatially high resolution — with hundreds of millions of cells.Confronted with high frequency real-time data, engineers facethe dilemma of either running the simulator in smaller timesteps, in line with the high frequency data, or adhering to thelarge time step practice. Some prefer to reduce the high fre-quency well rate data to a lower frequency to decrease thecomputing time. Others choose to ignore the real-time dataand only use it qualitatively to guide the simulation study. InSaudi Aramco, our preferred approach is to run the simulationmodels at daily average time steps, which is made possible byour in-house GigaPOWERS simulator — Saudi Aramco’s giga-cell parallel reservoir simulator. This lets us take full advantageof intelligent field data and high resolution models withoutcompromising on quality.

The advent of digital oil field technology initiated a new era ofreal-time data acquisition, which facilitated continuous fieldmonitoring and swift intervention. Although yesterday’s or thelast hour’s real-time data is not “real time,” it can be classifiedas intelligent field data. Raw intelligent field data is usuallyrecorded and stored in second or minute intervals, and the volume of the data has been continuously increasing. Yet theadded value of the intelligent field data so far has outweighedthe challenges in the storage, validation and summarization ofsuch huge amounts of data. While reservoir engineers oftenstruggle with historical well data that is limited in nature andis measured at different time intervals, the continuous and syn-chronized data stream emerging from the intelligent field pro-vides unique opportunities to improve the history matchingprocess of reservoir simulation models.

In this article, we present the data utilization and the work-flows adopted to integrate such data into reservoir simulationmodeling. The workflow was devised to manage data quality,consistency, conversion and reconciliation with allocationdata. Challenges lie in the selection of the intelligent field datato match, and in simulator reported pressure and time stepping.Continuous and synchronized data streaming in real time meansthat data is available to the engineer almost instantly or withina short time frame from acquisition. The wealth of data enablesthe simulation engineer to appropriately diagnose and accountfor critical reservoir phenomena, such as well interference andsubsurface well responses to surface well actions. Successful integration of intelligent field data into reservoir simulationsignificantly enhances the quality and predictability of ourmodels. This builds on the success of our high resolution geo-logical models that attempt to capture all spatial heterogeneities.In much the same way, high resolution temporal data attemptsto capture all dynamic actions and reactions within the reservoirto further improve the reservoir simulation models.

INTRODUCTION

Digital oil field technology is now mainstream and its deploy-ment by oil and gas companies has been going on for someyears1. A robust platform comprising hardware and software

Integrating Intelligent Field Data into Simulation Model History Matching Process

Authors: Bevan B. Yuen, Dr. Olugbenga A. Olukoko and Dr. Joseph Ansah


INTELLIGENT FIELD DATA TYPES FOR SIMULATIONMODEL HISTORY MATCHING

By design, intelligent fields are equipped to gather and storemassive amounts of different types of data in real time fromsensors that monitor reservoir response and the operation his-tory of the production equipment installed in individual wellsand surface facilities. The rationale behind this effort is thatdifferent entities within an organization or company use differ-ent sets of the same data. By applying a diverse set of softwareand tools, these different groups within the organization cananalyze the real-time data to ensure efficient oil and gas pro-duction, as well as optimize fluid injection systems that sup-port this production.

In reservoir simulation, only a subset of the intelligent fielddata is essential for proper history matching of the simulationmodels that will be used to monitor reservoir performance andforecast future production and injection requirements:

• Oil, gas and water production rates.• Water and/or gas injection rates.• Reservoir pressure.In a typical intelligent field, production wells are equipped

with multiphase flow meters (MPFMs) that provide oil, gasand water production rates in real time. These productionwells are additionally equipped with wellhead pressure (WHP)and temperature sensors that measure and store real-time pres-sures and temperatures. In some fields, pressure and temperaturegauges are installed downhole to enable pressure and tempera-ture measurements closer to the reservoir, ensuring accuratereservoir pressure data gathering, especially during production.The wellhead is also equipped with a choke system that remotelyregulates fluid production from individual wells. In this system,choke position sensors provide real-time choke position, whichis one of the key parameters for verifying the status of a well— open or closed.

All injection wells are equipped with wellhead water ratemeters that provide fluid injection rate data in real time. In ad-dition, injectors are equipped with pressure and temperaturegauges that provide real-time injection pressures and temperaturesat the wellhead. These wells are further equipped with surfacechokes to enable the injection of precise volumes of fluid.

Static reservoir pressures are provided by dedicated observa-tion wells located in key sectors of the field. These observationwells are equipped with permanent downhole measurementsystems (PDHMS) that continually measure and transmit real-time downhole static pressures and temperatures via the fieldsupervisory control and data acquisition system to intelligentfield servers, where they are stored. These static pressures, incombination with flowing and static reservoir pressures deter-mined from the production and injection wells, are keys forhistory matching reservoir simulation models.

The raw intelligent field data from different sources are fil-tered through special software tools to remove any outliersand then summarized on an hourly or daily basis, togetherwith calculated parameters, such as water cut and gas-oil ratio(GOR), into a usable format, Fig. 1.

The data is also plotted to observe trends and identify logicaland consistent data responses, especially when the wells areflowing or shut-in. Sample plots of the intelligent field data foroil producers and water injectors are shown in Figs. 2 and 3,respectively. In these plots, oil production, water productionand water injection rates, together with flowing bottom-holepressure (FBHP) and WHP, are plotted in real time.

KEY CONSIDERATIONS FOR INTELLIGENT FIELD DATAINTEGRATION INTO RESERVOIR MODELING

The availability of high frequency intelligent field data is bene-ficial for reservoir simulation modeling. The continuous pressureand rate stream, however, needs to be carefully incorporated

Fig. 1. Tabulated intelligent field data types relevant to reservoir simulation.


into the history matching process. The following are some keysteps to be considered for the utilization of intelligent fielddata in history matching when compared to conventional data.

Data Quality

Prior to utilizing the intelligent field data for history matching,it is important to ensure data quality and consistency betweenthe datasets, such as checking that buildups/falloffs correspondto zero production/injection periods. Data quality degradationis usually due to instruments malfunctioning, breaking downor being down for operational reasons. This can happen togauges, meters, data relay units and servers. Data missing overa short period of a few days may not have a big impact on simulation model history matching. For longer durations andwider fluctuation, the missing data must be backfilled and fil-tered by well models, expert systems or smart algorithms. Dataconsistency problems typically manifest as illogical responsesbetween pressure and rate data, such as getting non-zero

production rate measurements while the pressure gauge dataindicates a well is shut-in, or vice versa. Figure 4 shows an ex-ample of inconsistent data; the FBHP of an oil producer is ris-ing toward the end with zero production rates, but the chokeposition shows that the well is still open. This was resolvedthrough an integration of data and well rules. Tools that canquickly ensure quality assurance/quality control of the largeamount of data are indispensable.

Data Summarization and Conversion

As previously seen in Figs. 2 and 3, the measurement frequencyof intelligent field rates and pressures (hours: minutes: seconds)is often impractical for reservoir simulation purposes. On theother hand, conventional monthly production rates and infre-quent wireline static pressure measurements are sometimes toofar from reality. A compromise of daily average rates and pres-sures may be sufficient, depending on simulation hardwareavailability. Intelligent field data cannot be used directly and

Fig. 2. Intelligent field data — oil and water production rate and FBHP profiles.

Fig. 3. Intelligent field data — water injection rate and WHP profiles.


must go through a conversion process prior to being used inreservoir model history matching. In reservoir simulation, wellFBHP at top perforation and static well pressure at datum arecalculated from dynamic flow and well equations. During historymatching, the calculated pressures need to be compared to themeasured pressures to determine the quality of the match. Toachieve this, the producer’s FBHP is corrected to top perforation,and the injector’s WHP is converted to FBHP. These conversionsusually introduce some uncertainties, but to an acceptable degree. Further conversion of a well’s FBHP to static pressuremay be carried out by introducing an assumed well productivityindex (PI)/injectivity index (II), which involves additional uncer-tainties and is not recommended in instances where accuratestatic bottom-hole pressures (SBHP) are needed.

Data Reconciliation

Intelligent field data provides individual well flow rate meas-urements. Reconciliation with the allocated monthly data fortotal field measurement is usually difficult. In theory, the wholeis the sum of the parts, but in reality, there is usually a differencedue to inexact meter calibration, missing data, out of rangemeasurements and/or losses in the gathering and injectiontrunk lines. One analysis of producer rate data shows that thecorrection factor is centered on 1.0, Fig. 5. Therefore, in this

case, the MPFM rate is close to the allocated rate, leading tohigh confidence in the MPFM data used for history matching.

Focus on Shut-in Periods for Static Pressure Match

During the initial material balance step of the history matching,where the objective is matching the reservoir pressures whileprescribed fluid volumes are withdrawn, the primary focusshould be on the shut-in periods for producers and injectors, i.e.,the buildup and falloff pressures, in addition to the observedwell static pressures.

Utilize Model Cell Average Static Pressures Rather thanDrainage Area Pressures

Since the field pressure data are instantaneous measurementsat the well location, the well pressure output to be consideredfor the simulator should be based on the well average grid-block pressures rather than average drainage area pressures.This is because the latter attempts to mimic a field static pres-sure survey of a few hours or a couple of days for a shut-in period of a well by estimating the average drainage area pres-sure away from the well when the producing well is not actuallyshut-in, then use that estimation of static pressure in the model.For producer wells, however, a drainage area averaging method

Fig. 4. Producer missing data and inconsistent data.


will usually estimate a higher well static pressure than the cellaverage technique, especially for low permeability reservoirs,Fig. 6. Today, such averaging is no longer required as themodel will be run using the same (daily averaged) time steps asthe intelligent field data, which includes actual shut-in time.

Calibrate Well Index for FBHP Matching

Utilization of the intelligent field pressure data while a well is

producing or injecting, i.e., using the FBHP, requires that thewell’s PI/II be defined and/or calibrated in the model. Theseshould be specified in the model input if measurements areavailable and thereafter tuned to match the FBHP data. Itshould be noted that the well’s PI/II may vary during a well’sproducing life due to the changing operating conditions, e.g.,acid stimulation, fines migration, thermal fracturing (for waterinjectors), etc.

Fig. 6. Static cell pressure average and drainage area pressure average comparison.

Fig. 5. Well production rate reconciliation analyses.


WORKFLOW FOR INTEGRATING INTELLIGENT FIELDDATA IN SIMULATION MODEL HISTORY MATCHING

The workflow described here has been used in history match-ing several reservoir simulation models and is also being con-tinuously used for updating the models.1. Summarize the intelligent field data into daily interval time

steps. This involves filtering, removing outliers and ensuringthe consistency of the raw data. This can be done by an ex-pert system, statistical algorithms, logical rules and mathe-matical models.

2. Reconcile the intelligent field rates with allocation rates. 3. Convert the oil, gas and water production and injection

daily rates by wells into the reservoir simulator input format.4. Convert the producer’s FBHP from gauge depth to the top

of the perforation. Similarly, convert the WHP of the injec-tors to FBHP by using single-phase vertical flow equations. The observation well’s pressures are also converted from gauge depth to datum depth. More sophisticated well mod-els can be used for the conversion.

5. Add new wells to the simulation model.6. Perform the reservoir simulation with at least a weekly out

put of well pressure, water cut and GOR. Pressure responsesmay be missed if done at a monthly interval.

7. Match the static pressure of observation wells and also the static pressures during the shut-in periods of producers and injectors.

8. Fine-tune the well’s PI/II as necessary to match FBHP. With reasonable permeability around the well after matching wellstatic pressure, the well’s FBHP usually falls in place. If an extremely small or large PI or II is required to match a well’s FBHP, then the reservoir permeability is most likely incorrect.

EXAMPLE RESULTS OF INTELLIGENT FIELD DATA INTEGRATION IN MODEL HISTORY MATCH

By using the workflow just described, the high frequency rateand pressure data were incorporated in a simulation model.The history matching process was carried out the usual wayusing a combination of manual and assisted history matchtools. Traditional history matching uses monthly average allo-cated rates with infrequent SBHP measurements, resulting in awider uncertainty of the reservoir model. The averaged andnonsynchronized nature of non-intelligent field data meansthat the data do not capture the actual rates that correspond tothe pressure responses from the well itself and from any wellinterference. A model that is matched to intelligent field datahas reduced uncertainty due to the increased degree of con-straints in the data. Most of the wells show a very good matchwith the high frequency pressure data and to a lesser degreewith the water cut measured by MPFMs or from the allocationdata. Figure 7 is an example of a history matched producer.

The FBHP match, which is very good, was achieved by

Fig. 7. Producer FBHP, oil production rate and water cut matches.


following the approach to match the shut-in pressure, thenfine-tune the FBHP with modifications to the well’s PI. A cali-brated well PI tuned to continuous FBHP measurements willgive more credence to subsequent model predictions for thiswell as compared to predictions using a traditional model thatis history matched to only conventional data. Water cut alloca-tion issues are evident in the difference between the MPFMdata and the allocated data, as previously shown in Fig. 7. Inthis example, we chose to match the intelligent field data watercut rather than the allocation data due to a decreasing trend in

the latter — in the absence of any well intervention — whichindicates that the allocated data is less reliable. Figure 8 showsa fairly good match of the SBHP during well shut-in as esti-mated from the intelligent field FBHP.

The SBHP determined by the PDHMS is the most reliabledata and requires very little processing and conversion. TheSBHP match of an observation well is shown in Fig. 9, withpressure confirmation from wireline measurements (the periodin the graph that shows a lot of erratic measurement was dueto electric system glitches). Figure 10 shows the FBHP history

Fig. 8. Producer SBHP match.

Fig. 9. Observation well SBHP match.


match for a water injector. Daily water injection rates werespecified as input to the simulation model and the goal was tomatch the FBHP derived from the WHP. Frozen flow meterdata and differences with the allocation rates are evident. Asmost of the injectors were cleaned and not stimulated, a goodmatch of the FBHP was achieved via modifications to modelpermeability rather than to the well’s II.

ADVANTAGES OF INTEGRATING INTELLIGENT FIELDDATA

The main advantage of integrating high frequency real-time in-telligent field data for reservoir simulation modeling is the im-provement in the model quality and reliability. Connectivitybetween wells can be calibrated more reliably using high reso-lution rate and pressure data. As long as the flow meters arefrequently calibrated, the rate data is more reliable than theconventional data acquisition, which is often combined withinfrequent well test data. Well examples previously shownclearly highlight the difference between intelligent field data andallocation data, which is the majority of data collected andstored in the past. In addition, high frequency pressure datashould enhance the history match quality, as opposed to thedata from conventional and infrequent wireline pressure surveys.

CONCLUSIONS

Our experiences in history matching several reservoir simulationmodels to intelligent field data show that:

1. Filtering, processing, correction and conversion of the intel-ligent field data are required before it is usable for history matching.

2. Intelligent field data show that well rates and pressures varyconsiderably with time. Well events are accurately captured,which is impossible with monthly average rates and infre-quent static shut-in pressure measurements.

3. A detailed workflow for history matching intelligent field data was developed.

4. The most accurate static pressure data is from observation wells and during producer/injector shut-in. These pressures should be given the highest priority during history matching.The FBHP matches can be fine-tuned using an individualwell’s PI/II.

5. A reservoir simulation model history matched to intelligent field data is more reliable for both short-term and long-termprediction purposes since it is calibrated to a more extensivedataset than conventional monthly rates and infrequent static pressure data.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this article.


Fig. 10. Water injector FBHP match.


REFERENCES

1. AbdulKarim, A., Al-Dhubaib, T.A., Elrafie, E. and Al-Amoudi, M.: “Overview of Saudi Aramco’s IntelligentField Program,” SPE paper 129706, presented at the SPEIntelligent Energy Conference and Exhibition, Utrecht, TheNetherlands, March 23-25, 2010.

2. Al-Madi, S.M., Al-Aidarous, O., Al-Dhubaib, T.A.,AhmadHusain, H.A. and Al-Amri, A.D.: “I-Field DataAcquisition and Delivery Infrastructure: Khursaniyah FieldBest in Class Practices,” SPE paper 128659, presented atthe SPE Intelligent Energy Conference and Exhibition,Utrecht, The Netherlands, March 23-25, 2010.

3. Alhuthali, A.H., Al-Ajmi, F.A., Shamrani, S.S. andAbitrabi, A.N.: “Maximizing the Value of the IntelligentField: Experience and Prospective,” SPE paper 150116,presented at the SPE Intelligent Energy Conference andExhibition, Utrecht, The Netherlands, March 27-29, 2012.

4. Al-Mulhim, W.A., Al-Faddagh, H.A., Al-Shehab, M.A. andShamrani, S.S.: “Mega I-Field Application in the World,”SPE paper 128837, presented at the SPE Intelligent EnergyConference and Exhibition, Utrecht, The Netherlands,March 23-25, 2010.

5. Yuen, B.B., Abdel Ghani, R., Al-Garni, S., Olukoko, O.and Temaga, J.: “Utilizing New Proven Technologies inEnhancing Geological Modeling and Reservoir SimulationHistory Matching: Case Study of a Giant CarbonateField,” paper 152, presented at the 20th World PetroleumCongress, Doha, Qatar, December 4-8, 2011.

BIOGRAPHIES

Bevan B. Yuen is a Petroleum EngineerConsultant with the ReservoirSimulation Division. He has builtreservoir simulation models for ‘AinDar, Shedgum, Fazran, Abqaiq,Khurais, Abu Jifan and Mazalijproduction areas.

Prior to joining Saudi Aramco in 1999, Bevan workedfor Amoco Canada, Computer Modeling Group, CanadianOccidental and Qatar Petroleum.

He received his B.S. degree in Chemical Engineeringfrom the University of Alberta, Edmonton, Alberta,Canada, in 1979 and his M.S. degree in PetroleumEngineering in 1982 and a MBA degree in 1990, both fromthe University of Calgary, Calgary, Alberta, Canada. Bevan’s interests are in complex well modeling, andfracture and streamline simulation.

Prior to joining S

Dr. Olugbenga A. Olukoko is aPetroleum Engineering Consultant inthe Reservoir Simulation Division,where he has been carrying outreservoir simulation studies to supportfield development and reservoirmanagement activities. Prior to joining

Saudi Aramco in 2005, he worked for Shell and Pan OceanOil in Nigeria and the U.K. North Sea, holding variouspositions between 1988 and 2005 in both reservoir andpetroleum engineering.

He received his B.S. and M.S. degrees in MechanicalEngineering from the University of Lagos, Lagos, Nigeria,in 1986 and 1988, respectively. Olugbenga then receivedhis Ph.D. degree in Computational Stress Analysis fromImperial College, University of London, London, U.K., in1992.

Dr. Joseph (Joe) Ansah is a PetroleumEngineer Specialist with the SouthernArea Reservoir ManagementDepartment at Saudi Aramco, wherehe is involved in the development andmanagement of the fields in theKhurais Complex. Previously, he

worked for Halliburton and WellDynamics in the areas ofsmart well completions, hydraulic fracturing andconformance technology, underbalanced drillingtechnology, well testing and reservoir simulation. Prior tothat, Joe worked for Pennzoil E&P Company conductingproperty evaluation and field development in Houston andMidland, Texas.

He received his M.S. degree from the Gubkin RussianState University of Oil and Gas, Moscow, Russia, and hisPh.D. from Texas A&M University, College Station, Texas,both in Petroleum Engineering.

Joe has authored and coauthored over 18 technicalpapers in several industry journals and holds one U.S.patent. He also served on the Society of PetroleumEngineers (SPE) Editorial Review Committee from 2003 to2009.

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ABSTRACT INTRODUCTION

Maximizing the recovery factor by means of detailed mappingof hydrocarbon accumulations in the reservoirs is a key re-quirement for oil producing companies. This mapping is cur-rently done by interpolation of accurate measurements of fluidsaturation at the wells’ locations, but a knowledge gap existsin the inter-well volumes, where typically the only direct meas-urements available are density-based (seismic and gravity)data. These technologies are not always effective in discrimi-nating and quantifying the fluids inside the reservoirs (espe-cially when the difference in fluid densities is small, such asbetween oil and water). Consequently, when high electrical re-sistivity contrasts exist, as they do between hydrocarbons andwater, electromagnetic (EM) based technologies have the po-tential to map the distribution of the fluids, and if repeated intime, to monitor their movement during the life of the field,hundreds of meters or kilometers away from the wellbores.

The objective of an EM survey is to obtain resistivity andinduced polarization (IP) (or chargeability) maps of the reser-voir, from which it is possible to calculate the saturating fluidsdistribution. The specificity of the borehole to surface electro-magnetic (BSEM) method, compared to cross-well EM sur-veys, is such that a BSEM survey requires only one surveyedwell to obtain an areal map of fluid distribution within a reser-voir target layer kilometers away from the transmitting well-head — up to 4 km, as demonstrated in Saudi Arabian pilotprojects1, 2. A cross-well EM survey, on the other hand, allowshigher resolution results, but it is limited to cross sections be-tween two or more wells that are close enough for EM propa-gation — about 1 km in open holes and less in cased holes3.

The BSEM method in its time and frequency domain is anevolution of the controlled source EM method, a surface-to-surface EM technique. The BSEM technology was first em-ployed in the former Soviet Union at the end of the lastmillennium and has been extensively improved in the recentyears in China, where it obtained positive results; a commer-cial protocol was subsequently developed and introduced bythe Bureau of Geophysical Prospecting (BGP)4-6. SuccessfulBSEM pilot studies have been reported by Saudi Aramco asproducing resistivity and IP images of oil-water contact(OWC) at reservoir depth. In BSEM surveys, an electric current

The borehole to surface electromagnetic (BSEM) method andcross-well electromagnetic (EM) method have been shown toproduce adequate subsurface electric current to image fluiddistribution at reservoir depth. These methods have proven tobe an efficient way to transmit EM signals deep into the reser-voir, but their field deployment is potentially expensive and logistically challenging. This is because several days of loggingconveyance inside a borehole is required to implement them.

The ability to efficiently transmit EM signals inside thereservoir without a wellbore intervention would have atremendous potential impact in terms of cost reduction and deployment opportunity for reservoir fluid mapping and moni-toring, thanks to EM technologies already in the field. ForBSEM, a current electrode is placed inside the wellbore atreservoir depth and a counter electrode is located adjacent tothe wellhead at the surface. The reservoir fluids are then imagedthrough measurements of 1,000 EM receivers deployed at thesurface. An innovative approach described in this work is touse a borehole casing as a way to introduce an electric currentinto the earth at a considerable depth.

This new way to increase the current flowing in the subsur-face at large offsets from the well is to combine a casing withone or more remote surface electrodes located at a radial dis-tance of approximately the casing depth. Contrary to commonexpectations, a conducting casing is actually an advantagewhen used in conjunction with an electric source.

Further, we analyze the performance of two specific variantsof a casing combined with remote electrodes, showing the ca-pability to detect small electrical features at a depth of 2 kmout to greater than 2 km from the well. One of these sourceconfigurations has the considerable advantage of not requiringany well intervention for downhole operation. The model pro-jections are compared to pilot surveys conducted in Saudi Arabiaand at two sites in the USA with well depths of up to 2,100 m.Finally, we project the capability to detect small volumes of by-passed oil and establish the location of the oil-water boundaryat significant depth and offset from a vertical well.

Borehole Casing Sources forElectromagnetic Imaging of DeepFormations

Authors: Dr. Alberto F. Marsala, Dr. Andrew D. Hibbs and Prof. Frank Morrison


is injected into the earth via a source electrode using the con-figuration shown in Fig. 1. A downhole source electrode is deployed sequentially at two or more depths inside the boreholevia a wireline, and the transmitted electrical circuit is completedby a counter electrode located adjacent to the top of the well.Part of the electric current flows from the downhole electrodeto the counter electrode through the casing, and the rest flowswithin the earth, where it generates surface EM fields that arecharacteristic of the electrical properties of the subsurfacearound the well. The acquisition grid at the surface is composedof an array of about 1,000 electric field sensors deployed up to4 km around the EM transmitting wellhead. After data process-ing, the resulting maps reveal oil- and water-bearing zones inthe investigated reservoir layers.

Operating the downhole BSEM source electrode at twodepths and subtracting the respective datasets in post-process-ing is equivalent to deploying a single downhole dipole withseparation equal to the linear distance between the two down-hole depths. Simulations for a 50 m dipole in an uncased wellshow detectable change in both the surface electric fields and themagnetic fields that occur at the earth’s surface up to 5 km incases where a resistive fluid is injected at a depth of 2,500 m7.

In a cased well, the concern is that the very high conductivityof the steel pipe will act as an electrical short circuit betweenthe upper and lower electrodes of the BSEM source, resultingin negligible current flow in the surrounding earth. A pilot testof BSEM technology in a well with standard steel casing com-pletion and production tubing, however, showed that this isnot the case2. A primary signal level of 100 μV/m was reported

at 1 km from the wellhead8. This field level was approximately100,000 times greater than the achievable measurement noisefloor, opening the door to detecting those very small fieldchanges arising from fluid movement in the reservoir.

Next, we present the first calculations of the subsurface current and the surface electric field produced by one or moreborehole electrodes operating from a cased well. We then proj-ect the subsurface currents and the surface electric fields for aconventional BSEM configuration and two new source config-urations, described herein for the first time. The two newsources are designed specifically to exploit the capability of acasing to inject current into a subsurface formation.

STATEMENT OF THEORY AND DEFINITIONS

Basic Properties of the Three Basic Borehole Casing SourceConfigurations

The two new borehole source configurations are illustrated inFigs. 2a and 2b. In Fig. 2a, a downhole electrode is deployedat depth in the well in the same way as for a BSEM survey, butinstead of using a single electrode at the top of the well, thesurface electrode is implemented as a suite of four to 12 elec-trodes distributed in a partial or full circle of 1 km to 1.5 kmradius, approximately centered on the wellhead. Electric cur-rent flows down into the earth from this suite of electrodes, in-tercepting the casing along its entire length. Once it reaches thecasing, the current predominantly flows down the casing to thedownhole electrode — although in general some current inter-cepts the casing below the downhole electrode and flow up-wards. For convenience, we term the source configuration inFig. 2a a deep casing source (DCS). The initial motivation forusing the DCS was to increase current flow in deep offset re-gions from the casing, which would extend the lateral detec-tion range.

The second new borehole source configuration is similar tothat of the DCS except that instead of current flowing downthe casing to an electrode at depth, current flows up the casingand is returned by a simple electrode connection to the top ofthe casing, as illustrated in Fig. 2b. This configuration istermed a top casing source (TCS) with the significant benefitthat all required equipment is deployed at the ground surfaceinstead of downhole. In the event the suite of surface elec-trodes is deployed in a complete circle, the DCS and TCS aresimilar to a circular electric dipole9 except that they use a bore-hole casing energized at depth as the central electrode and noattempt is made to equalize the currents in each surface elec-trode. It should be noted that the currents and fields producedat any location by a conventional BSEM source are simply thedifference of those produced by the DCS and TCS, i.e., IBSEM =IDCS- ITCS.

A simple way to capture the behavior of a casing source isto note that at any point along a casing in contact with theearth, the current divides into a component flowing in the

Fig. 1. Conventional BSEM source configuration comprising an electrode at depthwithin a borehole and a counter electrode at the earth’s surface, adjacent to theborehole. The electric current within the ground is indicated by the lines andarrows (the current paths are only shown on one side, but they flow withapproximately azimuthal symmetry all around the borehole).


earth and a component flowing along the casing. For an infi-nitely long vertical casing in a uniform earth, the current flow-ing along the casing varies exponentially with the distance ofcharacteristic length Lc, given by Lc = √(Scρf) where Sc is thecasing conductance and ρf is the formation resistivity10. Forexample, for a 20 cm diameter casing in earth of resistivity 20Ω-m, Lc = 910 m.

The current injected into the formation, Iinj, is the spatialdifferential of the current flow along the casing, i.e.,

(1)

The casing dimensions and resistivity are generally stableand well-defined, and so the primary parameter that affects Lc

is the formation resistivity. For example, the variation of cas-ing current and injected current as a function of Lc is shown inFig. 3 at a depth of 1,500 m for a casing extending to a 1,600

m depth. Above a value of Lc = 900, the injected current is rel-atively independent of the value of Lc. Figure 3 therefore illus-trates a beneficial property of using a casing source in an EMsurvey: the current injected into the formation can be relativelyindependent of the formation resistivity. For example, if theformation resistivity for the entire half of the subsurface variesover the range from 25 Ω-m to 30 Ω-m, i.e., 20%, the Iinj inthe example of Fig. 3 varies by only 3.6%.

The variation of injected current along casings connected inall three source configurations is illustrated in Fig. 4 for anearth model of a conventional producing oil field. The modelcomprises a low resistivity (2 Ω-m) surface layer to 1,300 mdepth, a layer of moderate resistivity (12 Ω-m) from 1,300 m to1,500 m, a reservoir layer of thickness 15 m and resistivity 1Ω-m, and a base layer of resistivity 5 Ω-m to a depth of 4,000 m.The change in Iinj when crossing between each layer is immedi-ately apparent. Importantly, despite the fact that the contact tothe casing is made at opposite ends, the current injected intothe reservoir for the TCS is 60% of that produced by the DCS.

The effect of adding an annulus of thickness 15 m and resis-tivity of 8 Ω into the reservoir layer of the model used to gen-erate Fig. 4 is shown in Fig. 5. The center of the annulus is at adistance of 500 m from the casing, and the data is plotted as apercentage change to the current injected at reservoir depthcompared to the 50 m wide case. An annulus represents an ex-treme example of an anomaly because it intersects the radialcurrent in all directions. We see that there is less than 1%change in the current in the reservoir layer up to an annulus ofwidth, 200 m for the DCS and 400 m for the TCS. This is animportant result because it shows that for many geologic fea-tures of interest, the profile of the injected current along thecasing is not significantly affected by the resistivity structure ofthe earth, and can be calculated for the earth model alone inthe absence of a target body.

Detection of Subsurface Features via their Resistivity Contrast

The purpose of using a casing source is to extend the depth of

Fig. 2. The two borehole source configurations for depth to surface EM surveys:(a) with downhole electrodes, and (b) with the electrical connection at the top ofthe casing. Arrows show the direction of current flow in the casing at the sameinstant of the transmitted current waveform.

Fig. 3. Current flowing along a casing (Icas) and injected into a uniform earth at adepth of 1,500 m (Iinj) as a function of casing conductance length. Casing lengthis 1,600 m.


EM investigation to the depth of typical hydrocarbon reservoirs.A particular application is to image resistivity anomalies char-acteristic of hydrocarbon deposits. In Fig. 6, we calculate thesurface electric field signal produced by a 100 m wide x 100 mlong target in an earth model representative of the Marcellusshale formation for a surface source electrode at x = 0, y = 500m. The target is taken to be the difference between a matureshale region containing producible hydrocarbons that is charac-terized by a resistivity of 35 Ω-m and an immature hydrocarbonregion of resistivity 10 Ω-m11. The depth to the top of the shaleis 1,890 m and the reservoir formation is 60 m thick.

The contour plot shows that the surface field produced bythe conducting anomaly is well aligned with the physical loca-tion of the anomaly. The field differences projected in Fig. 6 areapproximately 10 times higher than the minimum detectablesignal for advanced electric field sensors. For example, a sensornoise level of 10-11 V/m can be achieved with less than 1 hourof recorded signal averaging. The field profile in Fig. 6b showsthat both the TCS and DCS provide a dramatically improvedcapability to detect and image hydrocarbon resistivity featuresat reservoir depth compared to surface EM methods. As previ-ously discussed, BSEM is equivalent to the difference of the TCSand DCS, and so in this example it gives a much reduced signal.

As a final study, we calculate the resistivity change due tothe motion of an OWC in a 2,000 m deep reservoir, which ischaracteristic of the geology in a Saudi Arabian super giant oilfield. We define two regions; an oil region with water satura-tion, Sw = 13% and resistivity 55 Ω-m, extending outwards asan annular region from the well, which is bounded by an outerwater region with Sw = 50% and resistivity 4 Ω-m. The reservoir

Fig. 4. Variation of injected current (mA) with depth (m) for the TCS, DCS andBSEM sources. The subsurface model comprises four layers: 0 m to 1,300 m withresistivity of 2 � -m; 1,300 m to 1,500 m with resisitivity of 12 � -m; 1,500 m to1,515 m with resisitivity of 1 � -m; 1,515 m to 4,000 m with resistivity of 5 � -m;and with casing to a depth of 1,600 m: (a) Injection current profile over all fourlayers, and (b) Injected current in the reservoir layer (1,500 m to 1,515 m).

Fig. 5. Change in injected current into the reservoir (%) vs. the width (m) of anannular resistive anomaly in the reservoir. The anomaly is centered at 500 m offsetfrom the casing. Reservoir resistivity is 1 � -m and the anomaly resistivity is 8 � -m.

Fig. 6. Predicted TCS signals for a 100 m x 100 m wide region with center at 537m indicative of a nonproducing zone in an earth model of the Marcellus shale: (a)Contour plot of the surface E-field signal per unit current produced by the anomalyfor a TCS, and (b) Profile of the field in the x-direction (Ex) along the x-axis forthe TCS compared with profiles for a DCS, BSEM and conventional surface EMsource at the same casing location.


is 26 m thick. To make the signal differences easier to view,Fig. 7 shows the surface field change for an oil to water bound-ary at three different distances from the well relative to the valueat 500 m. Importantly, the TCS produces a signal changewithin a factor of approximately 25% of the DCS source.

Again, these fields are detectable using presently availabletechnology. For a time-lapse measurement, considerable signalaveraging is possible, and the TCS opens the door to long-termmonitoring without the cost of opening the well and providinga wireline.

DESCRIPTION AND APPLICATION OF EQUIPMENT ANDPROCESSES

Pilot Tests of EM Borehole Casing Sources

Two successful pilot tests of a BSEM source were conducted bySaudi Aramco and the BGP, and results have been reported1, 8.In 2013, three successful tests of the TCS were conducted inNorth America: at a mature oil field, at a CO2 sequestrationsite and at a geothermal test well. Figure 8 shows an exampleof the electrical connection to the wellhead. A TCS is clearlyvery easy to configure and has the obvious advantage that thewell does not need to be opened. It is also clearly suitable forlong-term monitoring and permanent installation.

PRESENTATION OF DATA AND RESULTS

Figure 9 shows a comparison of the calculated and measuredsurface electric field along a 2 km line from a well in a produc-ing oil field in Montana. The two values of subsurface electri-cal resistivity as bounded by available well resistivity logs areshown. The agreement between the predicted and measuredsurface electric field is good, considering that other wells andshallow connecting pipes were also present at the site. Thepeak in the surface field at approximately 1,500 m from thewellhead is caused by the receiver line passing very close toone of the surface source electrodes, which were deployed on

Fig. 7. Change in surface E-field for three positions of the boundary between oiland water relative to the field for the same boundary at 500 m from a well in a2,000 m deep reservoir: (a) DCS, and (b) TCS.

Fig. 8. Photograph of a TCS connection to a wellhead for a pilot survey conductedin 2013.

Fig. 9. Comparison of the measured and calculated surface electric field producedby a TCS as a function of radial distance from the wellhead. The source has apartial ring of surface electrodes at a radius of 2 km.


a 1.5 km radius circle. The electric field at 1,800 m is 50μV/m; approximately 10 times the value per unit currentlymeasured at the same distance in Saudi Arabia for a BSEMsource. Overall, Fig. 9 demonstrates that the TCS can be usedsuccessfully in conditions relevant for hydrocarbon reservoirmonitoring.

CONCLUSIONS

Cross-well EM and BSEM are efficient ways to transmit EMsignals underground; they allow deep selective investigation ofreservoir layers, as demonstrated in recent surveys in SaudiArabia. Nevertheless, the costs and logistics linked to pro-longed downhole deployment of electrodes in the boreholecould limit their fast deployment potential.

The innovative idea is to use wellbore casings as “guidedwave antennas” to induce EM signals from the surface, goingdeep into the reservoir. The EM transmission occurs, connect-ing an electrode at the wellhead and a counter electrode buriedin the ground kilometers away. The EM signals, transmittedthrough the reservoir, are then recorded at the surface by ar-rays of hundreds of receivers. The borehole casing provides adistributed path to inject electrical current into the earth’s sub-surface down to the reservoirs. Two new casing sources are described that produce considerably larger signals than a con-ventional surface EM measurement and the recently introducedBSEM method. One of these sources, the TCS, has the furthersignificant advantage that it requires no downhole equipmentof any kind. Importantly, the current injected into the subsur-face by a casing varies as the differential of the current flowalong the casing, leading to beneficial results, in that the cur-rent injected at depth from a TCS can be almost as large for aDCS and larger than for the BSEM source. Through data pro-cessing, the outcomes of those methods are resistivity, charge-ability and fluid distribution maps of the investigated reservoir.The goal is to map and monitor fluid distribution in the inter-well volumes, supporting production optimization and recoveryincrease from the hydrocarbon fields.

A pilot field test was recently concluded, demonstrating theintrinsic safety of this EM transmitting method: At the wellhead,we measured a harmless mere 0.36 V (relative to the ground)on the casing connected to the source when transmitting EMsignals with the high power source (20A, 800 V) required toenergize a reservoir 4,000 m deep.

Numerical modeling of this innovative EM transmissionmethod validates its feasibility and potential to be deployed ex-tensively in the field, even in time-lapse applications. Further-more, an important issue for permanent monitoring is thelongevity of the system components in contact with the earth.For a system that relies on injecting current, a particular concernis degradation of the current injection electrodes. The TCS has aparticular advantage in this regard because only a simple metal-to-metal connection is made at the top of the casing, compared tothe need to provide electrical coupling within the fluid environ-

ment inside the wellbore for all other downhole-based sources. These developments considerably enhance the application of

EM methods to reservoir imaging. Both the TCS and DCSsources have the capability to detect fluid movements in anOWC using an array of electric and magnetic field sensors de-ployed at the surface. Because the TCS does not affect oil pro-duction, it could be considered for continuous operation, andused to provide permanent real-time monitoring in producingfields. When extensively field proven, this EM methodology willhave a tremendous potential impact in terms of cost reductionand the potential to be deployed broadly for fluid distributionmapping and monitoring in hydrocarbon fields.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco, GroundMetrics and Berkeley Geophysics Associatesfor their support and permission to publish this article.

This article was presented at the SPE Annual Technical Con-ference and Exhibition, Amsterdam, The Netherlands, October27-29, 2014.

REFERENCES

1. Marsala, A.F., Al-Buali, M., Ali, Z.A., Ma, S.M., He, Z.,Biyan, T., et al.: “First Borehole to Surface ElectromagneticSurvey in KSA: Reservoir Mapping and Monitoring at aNew Scale,” SPE paper 146348, presented at the SPEAnnual Technical Conference and Exhibition, Denver,Colorado, October 30 - November 2, 2011.

2. Marsala, A.F., Lyngra, S., Widjaja, D.R., Al-Otaibi, N.M.,He, Z., Guo, Z., et al.: “Fluid Distribution Inter-WellMapping in Multiple Reservoirs by Innovative Borehole toSurface Electromagnetic: Survey Design and FieldAcquisition,” IPTC paper 17045, presented at theInternational Petroleum Technology Conference, Beijing,China, March 26-28, 2013.

3. Marsala, A.F., Ruwaili, S.B., Ma, M.S., Al-Ali, Z.A., Al-Buali, M.H., Donadille, J-M., et al.: “CrosswellElectromagnetic Tomography: From Resistivity Mapping toInterwell Fluid Distribution,” IPTC paper 12229, presentedat the International Petroleum Technology Conference,Kuala Lumpur, Malaysia, December 3-5, 2008.

4. He, Z., Liu, X., Qiu, W. and Zhou, H.: “MappingReservoir Boundary by Using Borehole Surface TFEMTechnique: Two Case Studies,” SEG-2004-0334 paper,presented at the SEG Annual Meeting, Denver, Colorado,October 10-15, 2004.

5. He, Z., Hu, W. and Dong, W.: “Petroleum ElectromagneticProspecting Advances and Case Studies in China,” Surveysin Geophysics, Vol. 31, No. 2, March 2010, pp. 207-224.

6. He, Z., Zhao, Z., Liu, H. and Qin, J.: “TFEM for Oil


Detection: Case Studies,” The Leading Edge, Vol. 31, No.5, May 2012, pp. 518-521.

7. Beyer, J.H., Smith, J.T. and Newman, G.: “ControlledSource Electromagnetic (CSEM) Surveys to Monitor CO2,”presentation at the West Coast Regional CarbonSequestration Partnership Annual Business Meeting, Lodi,California, October 24-26, 2011.

8. Marsala, A.F., Hibbs, A.D., Petrov, T.R. and Pendleton,J.M.: “Six-Component Tensor of the SurfaceElectromagnetic Field Produced by a Borehole SourceRecorded by Innovative Capacitive Sensors,” SEGTechnical Program Expanded Abstracts, 2013, pp. 825-829.

9. Mogilatov, V. and Balashkov, B.: “A New Method ofGeoelectrical Prospecting by Vertical Electric Soundings,”Journal of Applied Geophysics, Vol. 36, No. 1, November1996, pp. 31-44.

10. Schenkel, C.J. and Morrison, H.F.: “Effects of Well Casing on Potential Field Measurements Using DownholeCurrent Sources,” Geophysical Prospecting, Vol. 38, No. 6, April 2006, pp. 663-686.

11. Schmoker, J.W. and Hester, T.C.: “Oil Generation Inferred from Formation Resistivity – Bakken Formation, Williston Basin, North Dakota,” Transactionsof the 13th SPWLA Annual Logging Symposium, June 14,1989.

Dr. Andrew D. Hibbs is a leadingscientist and industrialist in the lowfrequency electromagnetic sensingcommunity. He was one of thefounders of Quantum Magnetics(QM), a pioneer in aviation securitytechnologies, which was acquired by

InVision Technologies in 1998 and later by General Electricin 2004. Prior to the acquisition of QM in 1998, Andrewfounded Quantum Applied Science and Research(QUASAR) to develop bioelectric sensing systems, and hehas since spun out four other companies from QUASARcovering diverse applications of EM sensing, includingEEG, ion channel measurements, lightning research, andcovert facilities detection and monitoring.

Among other pursuits, he is currently serving as ChiefTechnology Officer of GroundMetrics Inc., which ispursing electromagnetic applications in subsurface imagingfor resource exploration and extraction monitoring.

Prof. Frank Morrison is currently a P.Malozemoff Professor Emeritus ofMineral Engineering at the Universityof California, Berkeley, and thePresident of Berkeley GeophysicsAssociates.

During his long and distinguishedcareer, Frank has conducted research and done field andlaboratory work on a wide range of topics in appliedgeophysics. Subjects have included numerical modeling ofelectrical, IP and electromagnetic (EM) methods, fieldstudies of controlled source EM and self-potential methodsfor geothermal exploration, ground and marinemagnetotellurics (MT) for petroleum exploration, audiofrequency MT profiling for mineral and groundwaterexploration, development of the theory and a full-scaleprototype for a unique single coil airborne EM system, andtheory and field systems for EM imaging betweenboreholes.

He developed a new induction coil sensor for highsensitivity measurements of low amplitude magnetic fieldsand incorporated these sensors in the first portablemagnetotelluric system.

Frank was a co-founder of Electromagnetic Instruments,which successfully commercialized the new MT system.Working with Ed Nichols, he developed a controlled sourceaudio frequency MT system designed to enable a newgeneration of groundwater exploration methods. Thissystem was transferred to Geometrics and is now marketedas the Stratagem system.

For his accomplishments and for his role in translatingthe results of many research projects into practical methodsfor the exploration industry, Frank was elected anHonorary Member of the Society of ExplorationGeophysicists (SEG) in 1999. He has published over 70papers in recognized geophysical journals.

Frank received his Ph.D. degree in Engineering Sciencefrom the University of California, Berkeley, CA, in 1967.

BIOGRAPHIES

Dr. Alberto F. Marsala has more than20 years of oil industry experience. Forthe last 8 years, he has been workingin Saudi Aramco’s Exploration andPetroleum Engineering Center –Advanced Research Center (EXPECARC). Alberto started his career with

Eni and Agip, where he participated in several upstreamdisciplines, including 4D seismic, reservoir characterization,petrophysics, geomechanics, drilling and construction inenvironmentally sensitive areas. Alberto worked on theTechnology Planning and R&D committee of Eni. He wasHead of Performance Improvement for the KCO jointventure (Shell, ExxonMobil, Total and others) concernedwith the development of giant fields in the northernCaspian Sea.

Alberto is now the Focus Area Champion for DeepDiagnostic on the Reservoir Engineering Technology teamof EXPEC ARC, where he is pioneering innovativetechnologies for advanced mud logging, logging whiledrilling, and gravity and electromagnetic methods forreservoir mapping and monitoring.

In 1991, Alberto received his Ph.D. degree in NuclearPhysics from the University of Milan, Milan, Italy, and in1996, he received an M.B.A. in Quality Management from theUniversity of Pisa, Pisa, Italy. He also holds a Specializationin Innovation Management, received in 2001.

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F k h

Eni and Agip where


ABSTRACT The polymers are usually used at concentrations of 1,000 ppmto 2,000 ppm in the flood water. Recently, higher polymer con-centrations were required to achieve a given viscosity underconditions of high salinity and high temperature10. Leonhardtet al. (2013)11 presented field trial results for polymer floodingwith a biopolymer, schizophyllan, in a high salinity reservoir(186 g/L total dissolved solids (TDS)). Also, some new syn-thetic polymers have received attention in recent research andfield applications, such as sulfonated polymers and sulfonic as-sociative polymers12-15.

The role of a polymer in a chemical EOR process is primarilyto reduce the mobility ratio by increasing the viscosity of thewater16, although other mechanisms like viscoelastic effect areinvolved17. It improves oil recovery beyond that achieved bywaterflooding or surfactant flooding alone by increasing thecontacted volume of the reservoir. In addition to increasingwater viscosity, polymer reduces the permeability of the reser-voir matrix. This further lowers the effective mobility of the injected fluid by increasing the residual resistance factor(achieved with permeability reduction). When the permeabilityis reduced, a lower polymer concentration can be used to gainequivalent mobility control.

This study targeted a representative carbonate reservoir inthe Middle East. The challenges were the high salinity of thereservoir brines and high reservoir temperatures. The evalua-tion of the polymers included tests of their compatibility withvarious formation brines, a rheology study, assessment of theimpacts of salinity and temperature, and tests of the polymer’slong-term stability. The results of this work demonstrate thepotential application of polymers under extremely harsh reser-voir conditions and their promise as good additives for EOR incarbonate reservoirs.

CHALLENGES OF CHEMICAL EOR IN CARBONATERESERVOIRS

Significant challenges exist in the development of chemicalEOR methods for carbonate reservoirs due to the complexityof the rock mineral compositions, matrix pore structures, rocksurface properties, fracture densities, aperture and orientations,as well as the different oil types18, 19. Carbonate rocks are aclass of sedimentary rocks composed primarily of carbonate

As part of the screening process for chemical enhanced oil re-covery (EOR), 18 polymer samples were screened as co-injec-tants in a surfactant-aided waterflood scheme. Due to theirhigher viscosity, polymers improve waterflood sweep efficiencyand reduce the permeability of the rock matrix, therefore helpingto improve oil recovery. Aimed at a representative carbonatereservoir in the Middle East, the polymer screening study focusedon polymer solubility and viscosity retention in high salinitybrines, equivalent to the reservoir parameters. The polymershad to pass through a stringent screening process to meet theharsh conditions encountered in the reservoir: high temperatures,high salinities and the nature of the carbonate. Salinity effectwas studied in a range of brines that included shallow formationwater, produced water and connate water. Among the polymersstudied, six were found compatible and have been shortlistedfor EOR use. Based on rheological measurements and flowcurves, the concentrations of the polymers were determined toachieve the target viscosity under reservoir conditions. Long-term stability and adsorption tests were conducted to ensurethe continued efficiency of the polymer when exposed to reser-voir conditions. Oil displacement tests with a selected polymershowed an increased oil recovery factor of 11% by polymerflooding and 18% by surfactant polymer (SP) flooding. Thisstudy demonstrates the potential application of polymers un-der extremely harsh reservoir conditions and their promise asgood additives for chemical flooding.

INTRODUCTION

Water soluble polymer is one of the key components in achemical enhanced oil recovery (EOR) process. It has beenused in processes of polymer flooding alone1, 2; polymer co-injection with surfactants, such as in surfactant polymer (SP)flooding3-5 or alkaline SP flooding6-9; and as a preflush/post-flush slug in surfactant or alkaline flooding.

Usually, two kinds of polymers have been used in the field: asynthetic polymer classified as polyacrylamide and a biopolymerknown as xanthan. More than 90% of polymers consumed forchemical EOR are the acrylamide type, whereas biopolymerslike xanthan are used in the field to only a very limited degree1.

Laboratory Study on Polymers forChemical Flooding in CarbonateReservoirs

Authors: Dr. Ming Han, Alhasan B. Fuseni, Badr H. Zahrani and Dr. Jinxun Wang


minerals. The two major types are limestone, which is com-posed of calcite or aragonite (different crystal forms ofCaCO3), and dolostone, which is composed of the mineraldolomite (CaMg(CO3)2). The nature of carbonate rocks differsfrom that of sandstones, which are composed of quartz (SiO2)grains cemented together with a variety of minerals. The lithol-ogy is described as a lime mud, foraminifera detrital carbonate20.The detrital carbonate presents a bimodal pore system with apretty good permeability and porosity21. Despite its overall ex-cellent flow characteristics, the bimodal system poses uniquechallenges of recovering the oil remaining in the micropores.

Due to digenesis, carbonates tend to be more heterogeneous.Natural fractures are more common in carbonate rocks than insandstones. The high density of such fractures and the resultinghigh permeability zones present fluid flow uncertainty. In car-bonate reservoirs, Super-K zones are areas dominated by highlinear flow; they can be high matrix flow zones or faults andfractures22. The flow uncertainty in the presence of fracturesand high permeability zones tends to complicate the applicationof EOR in such reservoirs.

The zones of high permeability are important conduits forthe flow of oil in the early production stages of the reservoir.Subsequently, as the field matures, these same zones becomethe conduits for excessive water production. In an EOR projectinvolving the injection of expensive fluids, care needs to betaken to avoid the channeling of the slug through such conduitsto the producing well.

Harsh reservoirs are those with high brine salinity and hard-ness, and with high reservoir temperatures. Most field cases ofchemical flooding have been reported in moderate reservoirs.Figure 1 shows the current limitation of chemical EOR tech-nology on a salinity and temperature plot. The high salinityand hardness of the reservoir brine degrade the chemicals’ ef-fectiveness; polymers tend to precipitate when exposed to highconcentrations of divalent cations and will partition to the oilphase at high salinities. High reservoir temperature also affects

the stability of the chemicals, especially polymers. Some majorreservoirs in the Middle East are in the high salinity and hightemperature region. This presents significant challenges in theapplication of chemical EOR technologies.

A majority of the big carbonate fields are developed with aperipheral water injection scheme, where water is injected onthe flanks of the reservoir for pressure maintenance23-25. Theobjective of peripheral flooding is not only to maintain thereservoir pressure but also to sweep the oil efficiently. In spiteof the carbonate’s complexity and the wide variation in rocktypes and permeabilities, most of the big carbonate exampleshave experienced semi-uniform flooding. For some major car-bonate reservoirs with decent porosity and permeability, thegravity/sudation force plays an important part in the depletionprocess26 and the oil recovery can reach about 50% by meansof a peripheral waterflood. In peripheral water injection, thewell spacing is typically 0.5 km to 1 km. Such a large wellspacing leads to a delayed chemical flooding incremental re-covery response. The incremental response can also be reducedfurther as chemicals lose their effectiveness due to dispersionand adsorption. For this reason, in-fill drilling to reduce wellspacing is usually required for chemical EOR implementation.

EXPERIMENTAL STUDY

Materials

Brines. Simulated field brines were synthesized for the studybased on the corresponding water analyses, including connatewater, seawater (injection water) and produced water. The de-tailed water analyses are presented in Table 1. All the simulatedbrines were filtered through a 0.45 micron filter and deaeratedfor test use.

Polymers. Several parameters have to be taken into accountwhen screening polymers to find the best candidates for SPflooding in a Middle East carbonate reservoir. Good polymer

Ion Seawater (ppm)

Produced Water (ppm)

Connate Water (ppm)

Sodium 18,300 19,249 59,491

Calcium 650 4,360 19,040

Magnesium 2,110 938 2,439

Potassium n/a n/a n/a

Sulfate 4,290 1,299 350

Chloride 32,200 40,704 132,060

Carbonate 0 0 0

Bicarbonate 120 585 354

TDS 57,670 67,135 213,734

Table 1. Composition of field brinesFig. 1. Challenge in chemical EOR for Middle East carbonate reservoirs.


candidates should meet the following requirements:• Compatible with field brines.• Effective at low concentration (0.1% to 0.3%).• High viscosity (2 centipoise (cP) to 5 cP) over a wide range of salinity at 95 °C to 100 °C.• Long-term stability (<50% viscosity loss over 6 months at

95 °C to 100 °C).• Low adsorption onto formation rock (<1 mg/g-rock).• Available in large quantities.• Easily handled in the field.A total of 18 polymer samples were tested, including poly-

acrylamide, sulfonated polyacrylamide and associative poly-acrylamide, as well as polysaccharides like xanthan gum,scleroglucan and Welan gum. The chemicals listed in Table 2were renamed in this article to avoid commercialism and forconfidential concerns.

Rheological Measurement. A MCR 301 rheometer from An-ton Paar, Austria, was used for rheological measurement. Theinstrument enables the measuring of various viscoelastic prop-erties, including flow curve, creep and viscoelasticity. It isequipped with concentric cylinder geometry having shear ratesranging from 0.01 s-1 to 1,000 s-1.

Viscosity was also measured using DV II+Pro, a Brookfieldviscometer made in the U.S., for preliminary screening. Thespindle used was S18. The temperature was set at 25 °C.

Polymer Concentration. The polymer concentrations were verified by carbon analysis using a total organic carbon (TOC)analyzer made by Shimadzu, Japan.

Core Plugs. Natural core plugs with a 3.81 cm (1½”) diameterwere selected for the coreflooding tests. The diameter andlength of the plugs ranged from 3.7 cm to 3.8 cm and from 3.6cm to 4.6 cm, respectively. The air permeability, pore volumeand porosity of the core plugs were measured by routine coreanalysis.

The dried core plug samples were evacuated and saturatedwith the simulated formation brine. The saturated plugs wereimmersed in the simulated formation brine to establish ionicequilibrium between the rock constituents and the formationbrine. Brine permeability was then measured using the simulated

CoreNum.

Length(cm)

Diameter(cm)

Porosity(fraction)

AirPermeability

(md)

PoreVolume

(cm3)

BrinePermeability

(md)

Corefl oodingTest

1 4.95 3.785 0.188 633 10.471 501 Polymer Adsorption

2 4.44 3.798 0.168 513 8.458 441 Polymer Adsorption

3 4.42 3.768 0.275 445 13.566 315Adsorption of Surfactant and

Polymer

4 4.64 3.798 0.165 428 8.664 304Adsorption ofSurfactant and

Polymer

5 4.69 3.785 0.121 175 6.392 N/A Polymer Flooding

6 3.61 3.790 0.232 122 3.94 N/A SP Flooding

7 4.62 3.800 0.214 134 6.73 N/A SP Flooding

Table 3. Petrophysical properties of core samples for coreflooding tests

Polymer Polymer Type Polymer Form Active (%)

PST01 HPAM Powder 86.92

PST02 Sulfonated PAM Powder 91.80



PST05 Biopolymer Powder 88.84




PST09 Modifi ed PAM Powder 88.17

PST10 Modifi ed PAM Powder 88.49

PST11 Associating PAM Powder 93.62

PST12 Associating PAM Powder 91.06

PST13 High Molecular Weight PAM Powder 88.04






Table 2. Polymers collected for screening


formation brine. Table 3 lists the detailed porosity, pore vol-ume, air permeability and brine permeability for the test samples.

Coreflooding Tests. The FDES-645 coreflooding apparatus,made by Coretest System, USA, was used in this study. Theschematic setup is shown in Fig. 2. Injection pressure, confin-ing pressure, pore pressure, differential pressure and flow ratewere recorded automatically during the test. The specific testprocedures are described later for the experiments investigat-ing dynamic adsorption and oil displacement.

EVALUATION OF POLYMERS IN BULK SOLUTIONS

Compatibility with Brines

Studies of the compatibility between reservoir fluids and poly-mers are in many cases critical to predict whether the polymercan be applied successfully. This is because the efficiency of apolymer solution will be greatly reduced if there are precipita-tion and insoluble particles when the solution encounters incompatible brines. Therefore, compatibility tests were con-ducted for all the polymers with respect to field brines.

Polymer solutions with 2,000 ppm active component wereprepared in different field brines. The solutions were sealedand put in an oven at 95 °C, then observed visually for evidenceof precipitation. The results were recorded by compatibilitycodes of A: clear solution; B: slight hazy solution; C: hazy solu-tion; and D: precipitation, Fig. 3. Table 4 illustrates the resultsof the compatibility studies with different field brines. Basedon this study, seven out of the 18 polymers were eliminatedfrom the candidate list.

Viscosities of Polymers in Brines

The viscosity of a polymer is one of the critical parameters toevaluate its effectiveness in a given reservoir environment, especially one with high salinity and temperature. A polymer’sviscosity depends on its chemical structure (type, componentand molecular weight) and its configuration (coil and rod) inbrine. Figure 4 shows the viscosities of the candidate polymers indifferent brines (seawater, produced water and connate water).With this test, we eliminated four more polymers having lowviscosity due to low molecular weights, although these polymerspresented a strong potential to tolerate high salinity and hightemperature environments.

Rheological Characteristics

Rheological study of the deformation and flow of matter underthe influence of an applied stress provides insight into the de-formation/flow behavior of the material and its internal structure.The rheological properties of polymer solutions play a very im-portant role in characterizing the polymers and determiningtheir likely performance and effectiveness.

Polymer solutions are known to exhibit non-Newtonian,shear-thinning fluid behavior. In other words, the viscosity isdependent on the shear rate. Actually, the viscosity-shear rate

Fig. 2. Schematic setup for coreflooding tests.

Fig. 3. Compatibility codes.

Polymer Seawater Produced Water

Connate Water Remark

PST01 C C C Declined

PST02 A A A Excellent



PST05 B A A Excellent

PST06 B B B Good

PST07 C D D Declined

PST08 C C D Declined


PST10 A C C Declined


PST12 D D D Declined

PST13 C C C Declined






Table 4. Compatibility codes showing polymer compatibility with field brines


relationship exhibits a Newtonian behavior at low shear ratesand a power-law behavior at high shear rates. These propertiescan usually be determined in the laboratory using a rheometer.

This fluid performance is critical for assessing the field ap-plication of a polymer solution because the polymer solutionpresents different viscosities on the surface, at the perforationsand at different locations during its propagation in the reservoir.This phenomenon of differing viscosity is based on the factthat the configuration of a polymer changes with the velocity.The shear rate in the rock matrix is basically dependent on theflow velocity and rock properties, as seen in Eqn. 1.

(1)

where is shear rate, C is constant, � is velocity, k is perme-ability, and is porosity.

In this work, we demonstrate the characteristics of twopromising polymers: a synthetic polymer (PST02) and a poly-saccharide (PST06). Figure 5 shows the flow curves of PST02and PST06 at 2,000 ppm concentration in produced water at25 °C. PST06 is a biopolymer in a rod-like configuration, lead-ing to a high viscosity at a low shear rate range, and significantshear-thinning behavior and low viscosity at a high shear

range. PST02, in a coil configuration, also showed shear-thinningbehavior with an increasing shear rate.

The Carreau model was used to cover overall performancein a full range of shear rates. In the Carreau model, the viscos-ity function depends on the shear rate, Eqn. 2.

(2)

where 0 is zero shear viscosity, is infinite viscosity, (n-1) isslope shear thinning, and is rotational relaxation time,which is the inverse of the critical shear rate. The critical shearrate is the shear rate at which there is a transition from New-tonian to shear-thinning behavior. The rheological parametersin Table 5 were extracted from the flow curves. Figure 6demonstrates the fit of the model with the actual data. Theseparameters can be used to estimate the viscosity at any shearrate, including zero-shear viscosity and infinitive viscosity. It isimportant to simulate the viscosity for a numerical reservoirsimulator for a chemical EOR process when polymer solutionpropagates in the deep reservoir.

The variation of the viscosity of a polymer solution, , as afunction of concentration, c, can be described as:

(3)

Fig. 4. Viscosity of the test polymers in different brines.

Fig. 5. Flow curves of PST02 and PST06 solutions in produced water.

Parameter PST02 PST06

h0 20.3 cP 6,230 cP

h3

6.59 cP 2.06 cP

x 3.16 s 11.63 s

n-1 0.46 0.81

Table 5. Rheological parameters of PST02 and PST06 extracted from the flowcurves


Fig. 6. Simulation of flow behavior of 0.2% PST06 solution in produced waterusing the Carreau model matched with real data.

in which s represents solvent viscosity, k1 and k2 are constants,and [ ] is intrinsic viscosity. The is generally referred to aszero-shear viscosity, which is determined by a flow curve. The[ ] and the overlap concentration can be obtained by flow curves.

In a very low concentration range, [ ] can be determined byextrapolation of sp/c to c->0 as:

(4)

The [ ] is related to the size (gyration radius) of a singlemolecule in the solution, indicating the capacity to increase theviscosity. In general, at certain conditions, the polymer mole-cule weight, M, can be determined by the following relation-ship:

(5)

in which k is a constant, and a is a constant between 0.5 to 1.5.The overlap concentration, C*, is an important parameter

in describing a polymer solution. In polymer solution theory,polymer solutions are divided into regimes: dilute, semi-diluteand highly concentrated. The critical concentration betweenthe dilute regime and the semi-dilute regime is called the over-lap concentration. It corresponds to the solution where poly-mer coils begin to touch one another throughout the solution.

Table 6 summarizes the values of C* and [ ] for two poly-mers in different brines. Usually, polymer concentration is se-lected in a semi-dilute regime. Therefore, the concentrationused for PST02 should be much higher than that for PST06. Inthis regard, polysaccharides with a rod-like configuration insolution present advantages over synthesized polymers. This isconsistent with the literature.

Long-term Stability

To be effective, polymer solutions must remain stable for along time at reservoir conditions. Polymers are known to besensitive to chemical and thermal degradations, especially inthe presence of oxygen and oxidizing agents at high temperature.It is believed that the reservoir is an anaerobic environment.Therefore, the polymer solution is expected to be free of oxy-gen during its propagation in the reservoir. The polymer solu-tions were prepared by replacing oxygen using nitrogen for 2hours before putting them in the oven at reservoir temperature

(95 °C). The polymer solutions were taken from the oven periodically to measure the viscosity retention. Figure 7 showsthat some polymers can withstand 6 months under the givenconditions of 95 °C and an anaerobic environment, i.e., theyretain sufficient viscosity. With this test, the number of poten-tial polymers was reduced to four.

Interaction with Selected Surfactants

Because some polymers were screened as co-injectants for a SPflooding scheme, the compatibility of the polymers with se-lected surfactants was an additional criteria for the polymers.Although polymers and surfactants are added to the water fortheir independent functions, some interactions may arise. Suchinteractions when a polymer and a surfactant are present to-gether may lead to significant changes in the system properties,which are considered either beneficial or undesirable, dependingon the prevalent conditions.

Formulations of the promising polymers and surfactantswere developed by changing and tuning the concentrations ofthe chemicals and environments to get better SP compatibility,lower interfacial tension (IFT), higher viscosity, lower adsorp-tion and eventually higher oil recovery. Table 7 illustrates theproperties of some formulations studied. This led to the elimi-nation of polymer in formulation #8, which is obviously in-compatible with a selected amphoteric surfactant.

EVALUATION OF POLYMERS IN POROUS MEDIA

BrinePST02 PST06

C* (ppm) [h] (mL/g) C* (ppm) [h] (mL/g)

Seawater 1,700 2,352 268 14,909

Produced 2,323 1,722 218 18,348

Connate 5,405 740 - -

Table 6. Overlap concentration, C*, and intrinsic viscosity, [n], of PST02 and PST06


Fig. 7. Long-term stability of three polymer solutions in seawater in an anaerobicenvironment at 95 °C.

The polymer selected for further study, PST02, is a sulfonatedpolymer. The main objectives were to evaluate its dynamic ad-sorption or retention, the injectivity, and its oil recovery poten-tial in porous media with a carbonate nature. In some cases, aselected amphoteric surfactant was used as a co-injectant tostudy the performance of the polymer in the presence of thesurfactant, which could occur in a SP scheme.

Dynamic Adsorption

Two groups of dynamic adsorption tests were performed, in-cluding two tests for polymer adsorption and two tests for SPadsorption. The concentration of the polymer solution was2,000 ppm. In the SP mixture, both surfactant and polymerconcentrations were 2,000 ppm, making the total chemicalconcentration of 4,000 mg/L. Each injected chemical slug was5 pore volumes (PVs) in size. The injection of the chemical slugwas preceded by a seawater flooding and followed by post-sea-water flooding. All tests were conducted at a constant flowrate of 0.5 cm3/min with a net confining pressure of 1,300 psiand pore pressure of 3,100 psi at 100 °C.

The concentrations of the chemical collected in the effluentswere analyzed to calculate the amount of chemical producedduring the coreflooding test, which was then used to determinethe amount of chemical adsorbed onto the rock surface. Titra-tion and TOC methods were used for the concentration analy-sis. For the case of SP mixture injection, the titration and TOCanalyses were performed on alternative effluent samples to determine the surfactant concentration and the total SP con-centration, respectively.

The amount of chemical lost in the core sample can be determined by subtracting the total chemical produced fromthe total chemical injected based on the mass balance. The as-

sumption was that the chemical is uniformly adsorbed onto therock surface when the amount of produced chemical is negligi-ble at the end of post-seawater flooding. The chemical adsorp-tion per unit rock weight was then calculated from the totalamount of chemical loss during the coreflooding test and thedry weight of the core sample before it was saturated with theformation brine. The total mass of the injected chemical is theproduct of the total volume and the concentration of the in-jected chemical slug. The total mass of the produced chemicalis the sum of the chemical mass in each collecting tube, whichwas similarly calculated as the product of volume and concen-tration in each tube.

Two polymer injection tests were conducted. Figure 8 showsthe effluent polymer concentration fraction and the ratio of theeffluent polymer concentration (C) to the injected polymerconcentration (Co) as a function of fluid injected. The plot startsfrom the beginning of the chemical slug injection and ends wheneffluent concentration is negligible. The dots in the figure areexperimental data and the solid line is a smoothed curve. Fromthe analyzed effluent polymer concentration and the total amountof injected polymer, the adsorptions of polymer on the rocksurfaces were determined based on material balance, to be0.121 and 0.133 mg/g-rock for the two tests, respectively.

A mixture of surfactant and polymer was injected in twotests to investigate the competitive adsorption between poly-mer and surfactant. Figure 9 plots the effluent total chemicalconcentration fraction and the surfactant concentration frac-tion as functions of fluid injected for a test. Both concentrationfractions were calculated based on the injected total chemicalconcentration of 4,000 ppm. The total SP adsorptions were0.161 and 0.151 mg/g-rock for the two tests, respectively. Theadsorptions of surfactant in these two tests were 0.0834 and0.0872 mg/g-rock. The adsorptions of polymer were then

Formulation

Compatibility (Compatibility Code)

Phase Behavior (Winsor Type) Viscosity (cP) IFT at 90 °C

(dynes/cm)

25 °C 95 °C 25 °C 95 °C 25 °C 95 °C Simul. Eq.

#1 A A I I 45.8 11.5 0.00606 0.0096

#2 B B I I 16.9 4.84 0.00464 0.00769

#3 B C I I 20.0 5.62 0.337 0.479

#4 B B I I 19.2 5.45 / 0.0595

#5 A B I I 21.9 5.49 / 0.0461

#6 A B I I 59.6 6.7 0.0279 0.0549

#7 A B I I 26.2 8.96 0.04520 0.0479

#8 A C I I 20.2 5.71 / 0.0215

#9 B B I I 31.5 7.75 0.00939 0.0369

#10 A B I I 50.0 8.75 0.06250 0.0661

#11 A B I I 22.5 5.29 0.03650 0.0455

#12 A B I I 131.0 15.0 0.03370 0.0667

#13 A B I I 27.6 6.66 0.00740 0.0382

Table 7. Properties of study formulations


calculated by subtracting the surfactant adsorption from thetotal SP adsorption, which were determined to be 0.0776 and0.0638 mg/g-rock for the two tests, respectively.

Table 8 summarizes the results of all these four dynamic ad-sorption tests. Comparing the results of these two tests, it canbe seen that the adsorption of polymer was evidently reducedwhen surfactant and polymer were co-injected. The total SPadsorption in the case of chemical co-injection was very closeto the adsorption of polymer when only polymer was injected.

It indicated that the adsorption sites of the rock surface werecompetitively occupied by the polymer and surfactant.

Oil Recovery Potential

Two plug samples were prepared for tertiary oil recovery testsby polymer flooding and SP flooding, respectively. Initial watersaturation was established by centrifuge method using deadcrude oil. The samples were then aged for four weeks beforethe start of the oil recovery tests. Waterflooding was conducted

Fig. 8. Profile of effluent polymer concentration.

Fig. 9. Profiles of effluent polymer and surfactant concentrations.

TestNum.

AmbientPorosity(fraction)

Ambient Air Perm.(md)

BrinePerm.(md)

Injected Chemical

TotalAdsorption(mg/g-rock)

SurfactantAdsorption(mg/g-rock)

PolymerAdsorption(mg/g-rock)

1 0.188 633 501 Polymer 0.121 N/A 0.121

2 0.168 513 441 Polymer 0.133 N/A 0.133

3 0.275 445 315Mixture ofSurfactant

and Polymer0.161 0.0834 0.0776

4 0.165 428 304Mixture ofSurfactant

and Polymer0.151 0.0872 0.0638

Table 8. Summary of dynamic adsorption results

Fig. 10. Oil recovery curve of polymer flooding.

Fig. 11. Oil recovery curve of SP flooding.


using seawater at the constant flow rate of 0.5 cm3/min, netconfining pressure of 1,300 psi, pore pressure of 3,100 psi anda temperature of 100 °C. A chemical slug of 0.6 PV was injectedwhen the waterflooding oil production was negligible, andthen a post-waterflooding was followed.

The cumulative oil recovery as a function of fluid injectedfor Test 5 has been plotted in Fig. 10. Waterflooding oil recoverywas 61% original oil in place (OOIP). Then 0.6 PV of 3,000ppm polymer solution was used in this test and the tertiary oilrecovery reached 11% OOIP.

Figure 11 presents the oil displacement coreflooding experi-ment results using a selected formulation composed of surfac-tant and polymer. Waterflooding oil recovery was about 72%,and tertiary oil recovery by surfactant and polymer was 18%.These results indicate that significant tertiary oil recovery canbe achieved by the injection of a chemical slug composed ofthe selected SP combination.

CONCLUSIONS

1. Eighteen different types of polymers were evaluatedthrough a stringent sequential screening process to studythe feasibility of polymer flooding or SP flooding for arepresentative Middle East carbonate reservoir. Threepolymers among 18 candidates met the critical require-ments of compatibility with brines, viscosity, long-termstability, and compatibility with the selected surfactantunder hostile conditions.

2. A synthetic sulfonated polyacrylamide presented very lowdynamic adsorption on the carbonates in the range of 0.15mg/g-rock. When the polymer was co-injected with aselected amphoteric surfactant, the portion of the polymeradsorption was in the range of 0.06 to 0.08 mg/g-rock dueto the competitive occupation of rock sites by polymer andsurfactant. These phenomena indicate that the polymer canbe successfully applied in carbonate reservoirs owing to thelow adsorption. This allays a concern questioning if ananionic polymer could be used for carbonates with positivesurface charge.

3. The oil displacement tests showed that an incremental oilrecovery of 11% OOIP was achieved by polymer floodingusing 3,000 ppm of the synthetic sulfonated polyacrylamidein tertiary recovery mode at reservoir conditions. For SPflooding, the incremental oil recovery reached 18% OOIP.These results indicate the great potential presented byincremental oil recovery via polymer-related chemicalflooding.

ACKNOWLEDGMENTS

The authors would like to thank Saudi Aramco’s EXPEC Ad-vanced Research Center for permission to publish this article.The authors are grateful to the Chemical EOR team members

for their continued support and involvement in this study. This article was presented at the SPE EOR Conference at Oil

and Gas West Asia, Muscat, Oman, March 31 - April 2, 2014.

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17. Han, X-Q., Wang, W-Y. and Xu, Y.: “The Viscoelastic Behavior of HAPM Solutions in Porous Media and Its Effects on Displacement Efficiency,” SPE paper 30013, presented at the International Meeting on Petroleum Engineering, Beijing, China, November 14-17, 1995.

18. Ehrenberg, S.N. and Nadeau, P.H.: “Sandstone vs. Carbonate Petroleum Reservoirs: A Global Perspective onPorosity-Depth and Porosity-Permeability Relationships,”AAPG Bulletin, Vol. 89, No. 4, April 2005, pp. 435-445.

19. Manrique, E.J., Muci, V.E. and Gurfinkel, M.E.: “EOR Field Experience in Carbonate Reservoirs in the United States,” SPE paper 100063, presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma,April 22-26, 2006.

20. Han, M., Al-Sofi, A.M., Fuseni, A.B., Zhou, X. and Hassan, S.F.: “Development of Chemical EOR Formulations for a High Temperature and High Salinity Carbonate Reservoir,” IPTC paper 17084, presented at the International Petroleum Technology Conference, Beijing, China, March 26-28, 2013.

21. Clerke, E.A.: “Permeability, Relative Permeability, Microscopic Displacement Efficiency and Pore Geometry of M-1 Bimodal Pore Systems in Arab-D Limestone,” SPEpaper 105259, presented at the SPE Middle East Oil and

Gas Show and Conference, Manama, Bahrain, March 11-14, 2007.

22. Olarewaju, J., Ghori, S., Fuseni, A.B. and Wajid, M.: “Stochastic Simulation of Fracture Density for Permeability Field Estimation,” SPE paper 37692, presented at the Middle East Oil Show and Conference, Manama, Bahrain, March 15-18, 1997.

23. Malinowski, R.: “Water Injection, Arab-D Member, Abqaiq Field, Saudi Arabia,” SPE paper 85, presented at the SPE Middle East Regional Meeting, Dhahran, Saudi Arabia, March 27-29, 1961.

24. Rahman, M., Sunbul, M.B. and McGuire, M.D.: “Case Study: Performance of a Complex Carbonate Reservoir Under Peripheral Water Injection,” SPE paper 21370, presented at the Middle East Oil Show, Manama, Bahrain, November 16-19, 1991.

25. Kiani, M., Kazemi, H., Ozkan, E. and Wu, Y-S.: “Pilot Testing Issues of Chemical EOR in Large Fractured Carbonate Reservoirs,” SPE paper 146840, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, October 30 - November 2, 2011.

26. Pham, T.R. and Al-Shahri, A.M.: “Assessment of ResidualOil Saturation in a Large Carbonate Reservoir,” SPE paper 68069, presented at the SPE Middle East Oil Show,Manama, Bahrain, March 17-20, 2001.


Badr H. Zahrani works in SaudiAramco’s Exploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC) as aSenior Laboratory Technician inchemical enhanced oil recovery (EOR).He joined Saudi Aramco in 2006 as a

trainee, and then in 2008 he went on to work as anOperator in the Safaniya Offshore Producing Department.In 2009, Badr was transferred to EXPEC ARC. Hisexpertise is in the evaluation of EOR chemicals, and he hasbeen involved in many research and service projects.

In 2008, Badr finished his training in the IndustrialTraining Center (ITC) in Ras Tanura, Saudi Arabia.

Badr is a member of the Society of Petroleum Engineers(SPE).

Dr. Jinxun Wang works at SaudiAramco’s Exploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC) as aPetroleum Engineer in the chemicalenhanced oil recovery focus area of theReservoir Engineering Technology

Division. Before joining Saudi Aramco, he worked withCore Laboratories Canada Ltd. as a Project Engineer intheir Advanced Rock Properties group. Jinxun’s experiencealso includes 10 years of research and teaching reservoirengineering at petroleum universities in China.

Jinxun received his B.S. degree from the ChinaUniversity of Petroleum, his M.S. degree from theSouthwest Petroleum Institute, China, and his Ph.D. degreefrom the Research Institute of Petroleum Exploration andDevelopment, Beijing, China, all in Petroleum Engineering.He received a second Ph.D. degree in Chemical Engineeringfrom the University of Calgary, Calgary, Alberta, Canada.

Jinxun is a member of the Society of PetroleumEngineers (SPE) and the Society of Core Analysts (SCA).

BIOGRAPHIES

Dr. Ming Han works in SaudiAramco’s Exploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC) as aPetroleum Engineering Specialist inchemical enhanced oil recovery. Beforejoining Saudi Aramco in 2007, he

worked for China National Offshore Oil Corporation(CNOOC), where he was Lead Engineer in Oil FieldChemistry at the CNOOC Research Center working toimplement an offshore polymer flooding project. For morethan 10 years of his career, Ming worked for the ResearchInstitute of Petroleum Exploration and Development(RIPED) in China as a Research Engineer, conductinglaboratory studies and field pilots in water shutoff, profilemodification, polymer flooding and chemical flooding. Healso served Hycal Energy Research in Canada as aResearch Engineer.

In 1982, Ming received his B.S. degree in Chemistryfrom Jilin University, Changchun, China. He received hisM.S. degree from the University of Paris VI, Paris, France,and his Ph.D. degree from the University of Rouen, Mont-Saint-Aignan, France.

Ming is a member of the Society of Petroleum Engineers(SPE) and the American Chemical Society (ACS).

Alhasan B. Fuseni joined SaudiAramco in 2006 and is a member ofthe Chemical Enhanced Oil Recovery(EOR) team of the Exploration andPetroleum Engineering Center –Advanced Research Center (EXPECARC). Prior to joining Saudi Aramco,

he worked for the King Fahd University of Petroleum andMinerals (KFUPM) Research Institute as a ResearchEngineer, and for Hycal Energy Research, Calgary, Canada,as an EOR Technologist. Alhasan has taught an in-housecourse on core flooding applications in chemical EOR atEXPEC ARC, and he teaches the chemical EOR section ofthe course on EOR at Saudi Aramco’s UpstreamProfessional Development Center. He has authored andcoauthored several papers in petroleum engineering and iscurrently serving as a reviewer for Elsevier’s Journal ofPetroleum Science and Engineering.

Alhasan received both his B.S. and M.S. degrees inPetroleum Engineering from KFUPM, Dhahran, SaudiArabia, in 1985 and 1987, respectively.

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ABSTRACT oil field in Saudi Arabia. The subject reservoir has been pene-trated by hundreds of wells, both vertical and horizontal, pro-viding an excellent dataset for geologic characterization. Thereservoir thickness is 350 ft of carbonate unit with an uppersection dominated by grainstones and packstones, and a lowersection consisting of wackestones and mudstones. Porosity andpermeability increase toward the top of the unit, where theporosity range is between 22% and 28%. Permeability is ex-cellent and can reach several Darcies in the so-called Super-Klayers. The permeability is enhanced by the presence of veryconductive fractures identified through different characteriza-tion tools. The area of interest is a mature area that has beenproducing under peripheral waterflood for many decades.

The main objective of this study was to define the sweetspots in this sector and to study the possibility of furtherdrilling opportunities in these spots. Optimization of the well’slayout followed to ensure the optimum sweep efficiency and tomaximize recovery.

MOTIVATION

The study was motivated by the need to carefully assess thesweep efficiency between the injection line and the central pro-ducing area. The routine monitoring and surveillance datashows an excellent sweep in the bulk area; however, severalfacts support the existence of some delimited areas with con-cealed potential.

This hypothesis is supported by the findings from loggingthe subject reservoir in a well, Well-A, that is targeting anotherdeeper gas reservoir. Therefore, the dry oil column interpretedis higher than the pre-assumed oil column. Figure 1 illustratesthe location of Well-A on a net oil column and the actual welllog.

An interesting result was obtained from the logs of anotherwell, Well-B; a dead well shut-in for 9 years that was presumedto be in a swept zone based on previous surveillance results.Subsequently, a saturation log recently indicated an oil columnof about 35 ft. Accordingly, the well was put onstream, flow-ing 2,000 stock tank barrels per day (stb/d), and it has beensustaining a stable plateau for more than one year.

This study illustrates a comprehensive integrated approach toidentifying the potential locations for future development inone sector of a giant carbonate mature oil reservoir. The ap-proach uses various data from several sources, including reservoir surveillance, production performance, geological interpretation and numerical simulation data, and cohesivelycombines them to yield an informed decision when assessingfield development and management. The study area has beenunder peripheral waterflood for more than 50 years and isdominated by heterogeneity related to fracture corridors, ahigh permeability zone and reservoir zonation. These featureshave led to a preferential and uneven propagation of waterflow, which results in unswept oil bearing spots after produc-tion using the existing well’s layout and configuration.

The reservoir management team has developed an integratedworkflow to address these challenges by using several reservoirengineering methods and models, including water encroachment,reservoir opportunity index (ROI), fractional flow calculation,remaining volumetric and water flow paths. The designed work-flow consists of first creating derived attributes that describethese models and then filtering the sector area using those at-tributes to define the sweet spots. The selection and prioritizationof the defined sweet spots are subsequently supported by avail-able reservoir surveillance and production data. The scarcity ofreservoir surveillance and production data in some areas of thesector motivated the reservoir management team to stretch thelimits by capitalizing on logs from the gas wells penetrating theshallower oil reservoirs. The open hole logs of these wellsrecorded a thicker oil column than the column pre-estimatedusing the existing surveillance data.

As a result of these efforts, a development plan has been designed to ensure reserves depletion in the identified sweetspots by drilling new wells or sidetracking existing wells. Despitethe reservoir’s level of maturity, simulation forecasts indicatethat the area of interest has a lot of potential to sustain a highproduction rate.

INTRODUCTION

The area of interest is located in the central part of a carbonate

Sweet Spot Identification and OptimumWell Planning: An Integrated Workflow toImprove the Sweep in a Sector of a GiantCarbonate Mature Oil ReservoirAuthors: Dr. Ahmed H. Alhuthali, Abdullah I. Al-Sada, Abdullah A. Al-Safi and Mohammed T. Bouaouaja


CHALLENGES

The waterflood performance in the sector of interest is influ-enced by reservoir heterogeneity and the presence of a numberof features in the area1, 2. Aspects like fractures and Super-Kdistribution are expected to have an impact on the sweep,which increases the challenge level for efficient reservoir man-agement3.

Additional challenges are related to the reservoir’s level ofmaturity; all the wells are cutting water, and the flow profilesrecorded through the production logging tools (PLTs) show agradual decrease in the net oil column. As would be expectedin such a situation, surveillance measurements are focused onthe front tracking, which adds an additional difficulty to effortsto identify the spots trapped between the fracture corridor andpreferential paths or behind the general front4.

METHODOLOGY AND WORKFLOW

To fulfill the objective of the project, which was to identify thesweet spots, the reservoir management team has developed acomprehensive workflow to integrate the available data, usingan organized, information value-based method, under a unifiedplatform. Numerous data from various sources were utilized toconduct the study, including data from previous studies androutine reservoir surveillance as well as from simulation models.A substantial effort has been dedicated to collecting all thesedata and capturing them in a format that is readable by theplatform being used.

A number of attributes were defined to extract the appropri-ate value from the different data. Some of them are basic, suchas the water saturation, and others are advanced, like the waterflow map. In total, 10 attributes were defined: net dry oil map,isobaric map, water saturation, reservoir opportunity index

(ROI), well spacing, fractures, water cut map, producing oilthickness (oil bearing thickness), cumulative water flow map andcumulative fractional flow map. Cutoff values were selectedfor each attribute and were integrated to define the verticaland areal continuity of the expected sweet spots. Obviously,some of these attributes may represent the same value of infor-mation, so some of them were considered as primary selectioncriteria and others were considered as supporting selection criteria.

Once an area of interest was defined, it went through addi-tional assessments that included examining the volumetric balances and the offset well’s performance.

After encouraging results came from this assessment, thearea was classified as a sweet spot with an associated opportu-nity for development or for additional evaluation. Finally, thedevelopment scenarios were assessed through numerical simu-lation for performance forecasting. Figure 2 gives an outline ofthe adopted methodology, which will be detailed in the follow-ing paragraphs.

DATA GATHERING AND PROCESSING

Given the objectives and the study deliverables, different cor-porate databases and previous in-house studies were consultedto collect the following data:

• Reservoir description and surveillance data, including ini-tial well logs, production logs and reservoir saturation logs.

• Most recent history matched full field reservoir simulationmodel and the original geological model with fracture dis-tribution — the simulation model is a dual porosity/dual permeability model with an areal gridding of 250 m and a very detailed vertical subdivision of 45 layers5.

• The well’s setup data, including operating status, orienta-tion, deviation, and surface and subsurface locations.

• Reservoir pressure, production and injection data at field and well levels.

Fig. 1. Well-A and Well-B logs showing thicker oil column than the interpreteddata in the map.

Fig. 2. Project workflow.


Several queries were used to extract the relevant raw datafrom different sources. The raw data was then converted into aformat readable by the unified platform that was used to inte-grate the data.

ATTRIBUTES DEFINITION AND CALCULATION

This study established several reservoir engineering attributesas major elements in the sweet spot identification workflow.These attributes are directly or indirectly derived from waterencroachment models, fractures networks, ROI, fractional flowcalculations and numerical simulation results. The attributescan be categorized according to the originating source, Fig. 3.

The following mapping and property calculation techniqueswere used to generate these attributes:

• Isobaric map generated by the latest pressure survey data from key wells covering the area.

• Net dry oil column generated by estimating the current water level in each well, and subsequently the remaining oil thickness, from production and saturation logging tools.

• Water cut map generated by mapping the trend of the current water cut distribution in the area.

• Oil bearing column map generated by mapping the oil producing thickness identified as the lowest oil producinglevel.

• Fractures and a well spacing map generated from existingwell data, Fig. 4, and built to identify areas to be avoided,either because they are occupied by an existing well or because they are on a fracture pathway6.

• Water saturation model derived as a direct result from thecalibrated 3D simulation model.

• ROI computed by combining three indexes, reservoir quality index (RQI), mobile oil saturation (Som) index and pressure index7, in the following calculation:

whereP is reservoir pressure indexRQI is reservoir quality index: andSOMPV is oil saturated pore volume index: SOMPV = SO × PV.

• Cumulative water flow map generated by computing cumulative water flow through each grid block in the 3D simulation model, after which the 3D model is converted to a 2D model by summing up the cumulative water flow for each grid vertically; this provides useful information about the preferential water paths through the entire history.

• Cumulative fractional flow map generated from the 3D simulation model by computing the phase’s flow contri-bution for each grid block; this map is also compared to thefractional flow calculated from the relative permeability tables for each reservoir unit.

SELECTION CRITERIA

Once they were generated, the above mentioned attributeswere submitted to a selection process to identify reasonablecutoffs and ranges to define any favorable spot/location for future development.

Some attributes, such as the isobaric map, net oil columnmap and oil bearing map, were used for quality checking andproviding general trends of the sweep. They were used at theend of the project as extra filtering criteria to prioritize the se-lection of the sweet spots. As these maps generally show bot-tom-up sweep with good pressure maintenance all over thesector and cannot be used to identify opportunities, they arenot included as the main selection criteria.

For the attributes used for the main selection process, thecutoff value for each attribute was set as follows:

• Unfilled spaces and fractures distribution: Based on the current spacing in the reservoir sector, a cutoff of 500 m around each existing well and 250 m around the high confidence fractures was used to identify space to be avoided.

• Water saturation: A cutoff value of 50% was selected afterit was correlated and cross-checked with the two other conjugate attributes; the water cut map and the cumulativefractional flow map. Through the different evaluations, itwas determined that 50% water saturation will allow a reasonable oil flow, and through this analysis, that the water cut in such locations will not exceed 60%. Figure 5illustrates the attributes of water saturation, cumulative

Fig. 3. Attributes categorization.

Fig. 4. Well spacing and fractures distribution in a part of the sector.


fractional flow map and water cut map. • ROI: An empirical selection of 25% as the cutoff ensuring

the best reservoir opportunity was made, corresponding to a cutoff of 0.18, Fig. 6.

• Cumulative water flow map: A cutoff of 100,000 stb/d was set to identify the zones where the cumulative water flow passing through drops below that rate so the zones can be avoided when selecting the sweet spots, Fig. 7.

Although the water saturation is included in the calculationof ROI, it was kept as an independent attribute to provide anadditional control for the selection process, since other param-eters in the ROI, such as permeability and porosity, may havea balancing effect and dilute the water saturation effect7.

It is also important to note that a redundancy appears to ex-ist by including both the water saturation and the water flowmap; nevertheless, each of the two parameters provides differ-ent information. The water flow map is an additive value —summation through all layers of all water quantities passing aparticular grid block — whereas the water saturation cannotbe summed to give a holistic idea about the state of saturationin a particular location. Water saturation can only be averagedand this will flatten any resultant map.

DEFINING AREA OF INTEREST

The previously mentioned criteria and cutoffs were applied acrossthe study area to yield the green spots highlighted for each

attribute in Fig. 8 and defined as an area of interest (AOI). Thevarious attribute’s AOIs were then integrated into one map togenerate a master combined AOI covering the reservoir sector.

This AOI presents a certain areal and vertical discontinuity,in that some areas are of infinitesimal size and so do not justifyclassification as a realistic opportunity. A numerical cleaningtherefore was conducted to discard these zones. A total of 10 ftof continuous vertical hydrocarbon thickness and 0.25 km2 ofareal connected volumes (4 grid blocks) were used as lowerlimits for an area to be retained as an opportunity, Fig. 9. As a

Fig. 6. Reservoir opportunity index distribution.

Fig. 7. Cumulative water flow map in a part of the sector.

Fig. 5. Attributes of water saturation, cumulative fractional flow map and watercut map, respectively.


result of all of these screening methods, 40 spots were finallyidentified.

OFFSET WELLS REVIEW

To align the findings of the previous steps with an actualneighboring well’s performance, further filtering was appliedto the defined 40 spots using the available well history, reser-voir surveillance and production data. The spots then weregiven a risk factor based on an engineering judgment of thesedata and identified as high risk, low risk and acceptable risk

for future development. Wells situated in a polygon at a dis-tance of 1 km from the spot’s border were considered for thisreview. Production, surveillance and well layout data wereused to build evaluation cards for each spot, summarizing thereview and the engineering verdict for the offset wells, Fig. 10.

SWEET SPOTS VOLUMETRIC EVALUATION

Once the risk associated with each spot was defined, a rankingwas made based on the assessed volumes. The remaining oilvolume contained in each polygon spot was calculated fromthe simulation model prognosis. This volume was compared tothe spot’s initial oil in place (OIP) to extract the current recov-ery factor. Table 1 presents a summary of the 40 spots’ volumetric results; the spots are classified from the highestremaining OIP. The current recovery factor reflects the state ofreserves depletion in each spot. Therefore, though there are nowells in the spot’s polygon, the contained reserves may be

Fig. 10. Example of spot 15’s evaluation card.

R ank Spot Spot Evaluation

Initial Volumes (STOIP MMSTB)

Reaming Volumes (STIOP MMSTB)

Jan 2014

Produced Volumes (MMSTB)

Current RF %

Remaining Receivable Reserves (MMSTB)

1 15 Low Risk xxxx xxxx xxxx xxxx xxxx

2 17 Med Risk xxxx xxxx xxxx xxxx xxxx


4 16 Low Risk xxxx xxxx xxxx 13.6 xxxx

5 23 Low Risk xxxx xxxx xxxx 3.9 xxxx

37 40 Med Risk xxxx xxxx xxxx xxxx xxxx

38 35 Med Risk xxxx xxxx xxxx 43.6 xxxx


40 1 High Risk xxxx xxxx xxxx 45 xxxx

Table 1. Summary of the volumetric evaluation of different sweet spots

Fig. 8. Retained AOI from each attribute after applying the cutoff in a part of thesector.

Fig. 9. Examples of removed areas with no practical opportunity value and theretained spots.


draining indirectly from the reservoir through the offset wells.It is worth noting that the current recovery factor, remainingoil and current saturation, though correlated, do not bring thesame information value. The oil saturation is certainly an indi-cation of the sweep status, but it is categorized by grid blocks.Looking for an average saturation — with all the associatedrisk of losing all the singularities — will not give the same exactitude as a recovery factor figure.

SWEET SPOTS DEVELOPMENT AND WELL PLANNING

The volumetric evaluation shown in Table 1 summarizes thecurrent status of the spots and presents a basis for the develop-ment planning for these areas. The logical approach is to lookto the different parameters together to decide if the spot is suit-able for development through drilling new wells and sidetrack-ing existing wells, or if it is more effective to conduct a furtherevaluation of the region. It was decided to discard the high riskspots from the current development, keeping them for furtherevaluation through reservoir surveillance or monitoring. Thespots with low and medium risk were evaluated in terms of oilcurrently in place, i.e., whether there was a substantial amountof remaining oil; each spot was then evaluated in terms of re-covery factor. The current recovery factor indicates if the offsetexisting wells are able to drain those reserves or if additionalwells are needed to directly target those reserves. As it happens(Table 1, example spot #14), a spot containing a huge amountof OIP currently presents a high recovery factor. This indicatesthat there is no need to add additional wells, leaving only asidetrack of those wells showing low performance to be con-sidered. The process schematic is described in Fig. 11.

Drilling new horizontal laterals in the retained potential ar-eas was chosen as the main production development method,by either new drilling or reentry drilling from offset verticalwells. Later surveillance recommendations based on data fromPLTs and reservoir saturation logs will be provided to betterassess the discarded areas. Each of the individual spots willthen receive a final specific recommendation with the specificname of the well:

• New well(s) for development.

• Sidetrack of existing specific well.• Conduct production logging or saturation log in the

specific well(s).Well planning is optimized by defining the trajectory of the

horizontal section3. The lateral is typically placed in the bestlayer in the top of the reservoir, Fig. 12.

SIMULATION PREDICTION AND FINAL WELL LAYOUT

A total of 32 laterals were designed and nine new wells and 23reentries from existing inactive or marginal producers are illus-trated in Fig. 13. The reservoir contacts of these wells were optimized, with placement between 1,000 ft and 5,000 ft nearthe reservoir top, considering the current well’s spacing.

To better capitalize on the designed wells, the proposedwell’s production performances, production targets plateauand cumulative produced volumes were assessed through sim-ulation prediction. The prediction confirmed the added value

Fig. 11. Procedure for designating level of development for the sweet spots.

Fig. 12. Example of well sidetrack design.


of the majority of the wells (28 out of 32) and provided a basisto include these wells in the field business plan for the upcom-ing years. Figure 14 illustrates the proposed development ofspot #23 as an example.

CONCLUSIONS

This study presents a comprehensive workflow with clear logi-cal processes to seize the advantage of available reservoir datato identify future developments in a mature area of a giantfield. The data is integrated through an information value-based method that provides relevant attributes with which toconduct the study. In this study, 10 attributes were calculatedto describe reservoir characteristics in terms of saturation,reservoir quality, fluid flows, and production and surveillancedata. Cutoffs are applied to the defined attributes through awell-established selection process to delineate the areas of interest. Areas compliant with the selection criteria are then

submitted to additional evaluations, which integrate the offsetwell’s performance and surveillance data to further distinguishthe sweet spots. After a study concludes that development op-portunities are not limited to in-fill drilling in the mature crestalarea, but that potential spots also exist elsewhere, risk profilesare assigned to each spot based on volumetrics and the abilityof the offset well to drain the reserves in the spot. A risk andreward evaluation finally leads to the design of the best sce-nario for developing these spots or to the need for additionalevaluation requirements. These recommendations will serve tofeed the field development plan for the upcoming years.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this arti-cle. The authors also want to acknowledge the contributions ofSoha Hayek, Lajos Benedek, Sikandar Gilani and Saad Mutairifor reviewing the article and Nayif Jama for assisting with therequired simulation runs.


REFERENCES

1. Alhuthali, A.H., Al-Awami, H.H., Soremi, A. and Al-Towailib, A.I.: “Water Management in North ‘Ain Dar,Saudi Arabia,” SPE paper 93439, presented at the SPE

Fig. 13. Final proposed well development layout in a part of the sector.

Fig. 14. Spot 23 development example.


Middle East Oil and Gas Show and Conference, Bahrain,March 12-15, 2005.

2. Alhuthali, A.H.: “Optimal Waterflood Management underGeologic Uncertainty Using Rate Control: Theory andField Applications,” SPE paper 129511, presented at theSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, October 4-7, 2009.

3. Yuen, B.B.W., Rashid, O.M., Al-Shammari, M., Al-Ajmi,F.A., Pham, T.R., Rabah, M., et al.: “OptimizingDevelopment Well Placements within GeologicalUncertainty Utilizing Sector Models,” SPE paper 148017,presented at the SPE Reservoir Characterization andSimulation Conference and Exhibition, Abu Dhabi, UAE,October 9-11, 2011.

4. Pham, T.R., Al-Otaibi, U.F., Al-Ali, Z.A., Lawrence, P. andvan Lingen, P.: “Logistic Approach in Using an Array ofReservoir Simulation and Probabilistic Models inDeveloping a Giant Oil Reservoir with Super-Permeabilityand Natural Fractures,” SPE paper 77566, presented at theSPE Annual Technical Conference and Exhibition, SanAntonio, Texas, September 29 - October 2, 2002.

5. Alzankawi, O.M., Al-Houti, R.A., Ma, E., Ali, F.A.,Alessandroni, M. and Alvis, M.: “Mauddud FracturedReservoir Analysis, Greater Burgan Field: IntegratedFracture Characterization Using Static and Dynamic Data,”IPTC paper 17471, presented at the InternationalPetroleum Technology Conference, Doha, Qatar, January19-22, 2014.

6. Abd-Karim, M.G. and Abd-Raub, M.R.B.: “OptimizingDevelopment Strategy and Maximizing Field EconomicRecovery through Simulation Opportunity Index,” SPEpaper 148103, presented at the SPE ReservoirCharacterization and Simulation Conference andExhibition, Abu Dhabi, UAE, October 9-11, 2011.

7. Stabell, F.B., Stabell, C.B. and Martinelli, G.: “EffectiveAssessment of Resource Plays: Handling TransitionZones,” SPE paper 167724, presented at the SPE/EAGEEuropean Unconventional Resources Conference andExhibition, Vienna, Austria, February 25-27, 2014.


Mohamed T. Bouaouaja joined SaudiAramco in March 2013 as a PetroleumEngineer working in the Southern AreaReservoir Management Department.He started his career in Tunisia wherehe worked for the national oilcompany ETAP as a Reservoir

Engineer, involved in reservoir management for bothcarbonate and clastic reservoirs. In 2007, Mohamed joinedSchlumberger and worked in various assignments inconsultancy, simulation, training and project managementwith an international exposure and a focus on the ArabianGulf countries.

He has published several technical reports, studies andSociety of Petroleum Engineer (SPE) papers.

In 2001, Mohamed received his B.S. degree in CivilEngineering Hydraulics from Ecole Nationale d’ingenieursde Tunis (ENIT), Tunis, Tunisia.

Abdullah A. Al-Safi joined SaudiAramco in 1986 as a PetroleumEngineer. During his career, he hasworked in several different productionfields and in various jobs, including asa Drilling Engineer and a ProductionEngineer. Abdullah currently works as

a Petroleum Engineer Specialist in the Southern AreaReservoir Management Department.

He has coauthored several Society of PetroleumEngineers (SPE) papers.

In 1986, Abdullah received his B.S. degree in PetroleumEngineering from King Saud University, Riyadh, SaudiArabia.

BIOGRAPHIES

Dr. Ahmed H. Alhuthali is a DivisionHead in Saudi Aramco’s Southern AreaReservoir Management Department,overseeing the reservoir engineeringand operational issues of the‘Uthmaniyah area — the largest in thegiant Ghawar field. Prior to this

assignment, he held reservoir management and productionengineering positions in different areas of Ghawar andAbqaiq fields. Ahmed has been with Saudi Aramco for 16years.

He is interested in integrated reservoir management withan emphasis on waterflooding principles, closed loopoptimization, well performance and probabilistic decisionanalysis. Ahmed is also interested in energy economics,especially in the oil and gas sector.

He received his B.S. degree in Electrical Engineeringfrom King Fahd University of Petroleum and Minerals(KFUPM), Dhahran, Saudi Arabia, in 1998 and an M.S.degree in Petroleum Engineering from Texas A&MUniversity, College Station, TX, in 2003. Ahmed receivedhis Ph.D. degree in Petroleum Engineering from TexasA&M University, College Station, TX. He also earned abusiness certificate from Mays Business School at TexasA&M University in May 2008.

Abdullah I. Al-Sada joined SaudiAramco in 2012 as a ReservoirEngineer working in the Southern AreaReservoir Management Department.He is currently working in the‘Udhailiyah Reservoir ManagementDivision involved in the reservoir

engineering and operational issues of the ‘Uthmaniyah area— the largest in the giant Ghawar field. Abdullah’sinterests include the reservoir management of mature fieldsand maximizing the efficiency of secondary recoverymethods with respect to the asset’s heterogeneity.

In 2012, he received his B.Eng. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

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ABSTRACT design of the well, to optimize reservoir contact and maximizethe return on investment.

Testing and field applications of newly proposed, developedand implemented MSS solutions are also presented, includingan innovative packer seal technique, an engineered approachfor optimal performance of fracturing sleeves, nonstandardball increment spacing sizes, curved ball seats and a segmentedbody for full bore mill-out.

INTRODUCTION

For over a decade, multistage stimulation (MSS) has been awell-established technique in North America and is also in aperiod of rapid growth in many regions in the Middle East.Globally, operators have applied a multitude of MSS comple-tion options to wells in many varying reservoirs, from conven-tional reservoirs, to tight gas/tight oil basins, to carbonate andclastic formations, to more unconventional shale and coalbedmethane reservoirs1-12.

A huge amount of information, best practices and tech-niques has been leveraged from the North American MSS experiences; however, as experience within the Middle East environment developed, differences among the MSS techniquesand processes became clear. Certainly as a starting point, thedifferences logistically between the North American marketand the international market are immediately evident; wheretens of stages (30, 40, 50 stages and more) are deployed andfracture stimulated over the space of days in North America,stimulating the same number of stages would take weeks inmany international locations. Therefore, the internationalstage count is significantly less and typically in open hole unce-mented applications. For example, outside of North America,a maximum of 10 stages can be deployed, with an average of 4to 5 stages, in a single lateral well. For that reason, a great dealof focus is placed on efficiency in North America, where inter-nationally, and in the Middle East in particular, the majority ofthe focus is on effectiveness. For example, in Saudi Arabia, iffive stages are deployed, a full five stages should be fracturestimulated to the fullest to be seen as contributing individuallyto their maximum potential.

With that said, judging from the previously installed openhole, uncemented, lower completion systems (of which there

To date, multistage stimulation (MSS) technologies have beenrun in almost every type of complex hydrocarbon-bearing rock,from the much heralded shale plays in North America to themassive heterogeneous carbonate formations exhibiting a dualporosity/dual permeability system in Saudi Arabia. These tech-nologies have also been used in offshore wells in the NorthSea, Black Sea and West Africa.

The main MSS market was and still is in North America, inthe tight unconventional shale plays; however, in recent years,the international market (outside of North America) has beensteadily catching up. One of the main leaders associated with thisincrease has been Saudi Aramco in its Southern Area gas fields.

MSS has often been viewed as simply running a completionstring followed by pumping services; however, the early attemptsat uncemented open hole MSS completions in Saudi Arabiawere met with mixed operational success. It became clear thatthe standard completion approach and stimulation procedurescould not be directly applied there. A new set of best practiceswould be required in these Middle East wells, one that includedan integrated multidisciplinary approach that took a step back-wards in the process — to the pre-drilling phase — and focusedon well planning optimization to maximize the multistagecompletion technique and ultimately the well productivity.

The wide range of reservoir types required engineering of theMSS completion to enable placement of a variety of matrix andfracturing stimulation techniques, further complicated by theconstraints associated with operating in environments rangingfrom land and/or the desert to offshore areas. These completionoptions have included low-tier sand plugs, more sophisticatedbridge and frac plugs, and high-end, open hole, uncementedliners with packers and sleeves. For Middle East wells, it isclear that “one MSS completion technique does not fit all.”

This article will discuss many of these MSS solutions andhighlight some of the debate over the merits of the variousMSS completion designs and options — such as the prefer-ences in isolation methods and options for connecting the well-bore to the reservoir — as deployed in the Southern Area tightgas fields of Saudi Arabia. Regardless of which MSS technologyis applied, further emphasis is being placed on the integrationof the completion and the stimulation treatment from the initial

Innovation in Approach and DownholeEquipment Design Presents NewCapabilities for Multistage StimulationTechnologyAuthors: Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Mustafa R. Al-Zaid and Fadel A. Al-Ghurairi


are approximately 80 in total) in the Saudi Arabia area, theequation of “number of stages deployed” being equal to“number of stages stimulated” is yet to be satisfactorily real-ized. One of the main issues is related to the difference between utilizing open hole MSS systems in a carbonate for-mation, where acid fracturing treatments are applied, and utilizing them in a shale formation, where proppant fracturingtakes place. The concerns when using a MSS system in an acidfracturing environment are the zonal isolation between stagesand ultimately the packer isolation technique selected.

A typical hydraulic-set mechanical packer uses one or twoseal elements that are approximately 8” to 10” in length whilebeing deployed, and then when the packer is hydraulically set,a piston force is applied to the solid rubber element, which isforced outwards, expanding in outside diameter while con-tracting in overall length. That means the more the packer’soutside diameter expands, the less the contact seal lengthpressed to the open hole formation face becomes.

This of course is assuming a perfect “gun barrel” open holecircumference where a mechanical packer can be set uniformlyto the formation face. The worst case scenario is when ovalityfrom washouts and breakouts is present. The mechanicalpacker attempts to conform to the open hole circumference;however, on occasions where ovality is present, the potentialexists for a micro-annulus space to occur between the packerseal and the formation face, Figs. 1 and 2. Now, in standardshale/sandstone MSS applications, where proppant rather thanacid is pumped, this micro-annulus leak path can easily packoff with proppant in what becomes a self-healing process, andthe isolation between stages is restored, Figs. 3 and 4. Giventhe nature of the acid fracturing treatment in a carbonate for-mation, however, this leak process is not self-healing, and thephenomenon of acid working its way through the micro-annu-lus and dissolving away the rock around the packer seal can bevery problematic.

There is a clear need therefore, for an optimized packer seal technique in MSS acid fracturing applications in carbonateformations.

PROPOSED MSS SOLUTION

Development and qualification of a fit-for-purpose multistageswellable element was required for use in the environment ofthe southern gas fields in Saudi Arabia, a packer that couldwithstand harsh conditions in terms of bottom-hole tempera-tures and pressures as well as the acid fracturing applicationneeded by the carbonate formations, Figs. 5 and 6.

Previous attempts had been made to use more conventionalstandard swellable packers, adapted from water shutoff or in-flow control device type applications. The challenge was alwaysfulfilling the differential pressure requirements of the fracturingtreatment, and the conventional method was to use standardapplication rubber materials and simply increase the length ofthe swellable elastomer. This resulted in the adoption of packerlengths of 32 ft or more to meet the high differential pressurerequirements of the multistage treatments. The positive outcomewas a longer seal length, and therefore, a reduced possibility ofthe acid dissolving the rock formation around the seal — ashighlighted earlier, that is a major concern for the acid fractur-ing application. The negative outcome, on the other hand, wasalways the impact of the longer seal length of the swellablepacker on deployment during the installation process. For ex-ample, with several long swellable packers being deployed in asingle lower completion string, reaching target depth became asignificant concern. A great deal of time and effort will be spentin determining the optimum stage lengths and open hole packerpositions prior to running the MSS equipment, but when thelower completion becomes mechanically stuck and ultimatelyset off depth, all this effort becomes wasted and the productionresults are ultimately never fulfilled.

The challenge of deploying MSS systems to target depth isnot new in Saudi Arabia, and even with hydraulic-set mechani-cal packers, the initial MSS systems saw installations prema-turely set several hundred feet off depth. The preferredconfiguration for running the MSS system involved havingevery fracturing sleeve placed between two open hole packers,resulting in what is known as a “balanced system,”13 wherethe fracturing forces are balanced between pressurized stages.The consequence of having a balanced system installation setprematurely was that the toe of the well was isolated by thelowermost open hole packer and therefore was unable to bestimulated. From that point, an open hole anchor packerwould be run in an “unbalanced” multistage configuration,meaning the first toe stage was unbalanced by having a frac-turing port placed below the lowermost open hole packer.Therefore, if the MSS completion system was set prematurely

Figs. 1 and 2. An acid fracturing case in a carbonate formation showing a slightwashout at the upper side of the lateral where the acid dissolving away some ofthe formation around the seal causes communication between stages.

Figs. 3 and 4. A proppant fracturing case in a shale/sandstone application showinga slight washout at the upper side of the lateral where packing off around the sealensures zonal isolation is achieved.

Figs. 5 and 6. The newly designed swellable element must achieve positiveisolation in carbonate formations with acid fracturing applications (left image), aswell as in sandstone/shale proppant fracturing cases (right image).


off depth, then there was still the possibility of stimulating thetoe section of the well, albeit if it was a very long section. Theupward forces placed on the bottom of the lowermost packer,however, would be very large, as per the term unbalanced, andsliding of that packer would be likely. So the idea of deployingan open hole anchor packer became of interest, with the intentof anchoring the bottom of the completion string and resistingthe movement caused by the large upward piston forces placedon that lower open hole packer.

This unbalanced configuration worked well in shale typeapplications. Consequently, in carbonate formations, on occa-sion during the acid fracturing treatments of the first stage, assolution was pumped through the hydraulic frac sleeve, signifi-cant and instantaneous pressure drops were noted, and it wasbelieved that the acid treatment had dissolved away the car-bonate rock around the slips, and therefore the anchor had released, creating an immediate upward movement of the lowermost open hole packer.

Once the deployment issues were rectified and completionsno longer became stuck14, 15, the standard practice of runningbalanced configurations resumed and the open hole anchorpacker become redundant. The proposed open hole solutionsthat followed did not require open hole anchor packers in thelower completion string.

A second challenge was related to the fracturing port config-uration. On occasion the integrity of the ball and ball seat in-terface came into question. For example, during treatmentswhere instantaneous pressure drops of several thousand psi ormore were seen in the middle of the acid fracturing process —typically this was interpreted as a mechanical failure — thecause was loss of integrity between the ball and ball seat inter-face. Therefore, a more robust fracturing sleeve that incorpo-rated a newly designed ball seat was tested and qualified.

Yet a coiled tubing (CT) mill-out of the ball seats in themultistage completions can be required in some cases16, 17. Theresults of previous CT mill-outs have been widely varied, andeven if the practice of CT milling has been significantly im-proved in terms of bottom-hole assemblies (BHAs), mills andmotors, as well as milling procedures, failures still occur.Therefore, the new, more robust ball seat was also required —from the opposite side — to be easily millable.

NEWLY DEVELOPED AND FIT-FOR-PURPOSESWELLABLE PACKERS FOR MULTISTAGE ACID FRACTURING APPLICATIONS

The development that followed resulted in a multistageswellable packer (MSwP) isolation system designed to achieveopen hole and cased hole isolation in many varied applica-tions, from well construction to well completion. The swellableelement is specially designed for the typically higher pressureratings associated with a multistage fracturing job, Fig. 7.

The swellable packer is engineered from a complex polymerthat has properties similar to those of rubber before swelling.

The mechanism of the oil swell technology is to use the ther-modynamic diffusion of hydrocarbons into the polymer net-work to cause stretching and volumetric expansion of thepacker. The MSwP system, which employs bonded-to-pipeswellable packers, integrates a patented, double brass foldback shoe design to act as an anti-extrusion device, ensuringbetter pressure and temperature ratings and reliability. TheMSwP assembly also has a built-in swelling delay mechanismthat allows thermodynamic absorption to start immediately af-ter installation. This delay, achieved without any external coat-ings, reduces premature swelling risks while the assembly isbeing run in the hole. Because of the MSwP assembly’s ad-vanced polymer construction and its anti-extrusion device de-sign, its differential pressure capabilities are suitable for highfracturing pressures — an indispensable criterion for a fractur-ing packer if isolation is required.

MSWP BONDED-TO-PIPE SWELLABLE PACKERS WITHFOLD BACK SHOE TECHNOLOGY

Multistage operators have expressed concern that swellablepackers may not reliably seal open hole completions. To inves-tigate this concern, benchmark testing was undertaken. Thetest results support the idea that industry pressure ratings maybe marginal. For example, the industry length for 6,000 psiservice is around 6 ft, and although it is possible to approachthis pressure with conventional designs, overall performancehas been suspect.

A root cause analysis identified the annular extrusion gap asa limiting factor in pressure capability. The industry method tocompensate is to increase the element length. While helpful,this adds cost and fails to address the root cause of the weak-ness. To remedy the problem, a patented, cost-effective foldback shoe technology was designed. The fold back shoes arefixed to the ends of the element. Swelling and axial pressuresdeploy the shoes to cover the annular extrusion gap. This fea-ture yields industry-leading pressure performance and reliabil-ity. Figures 8 and 9 illustrate the fold back shoe technology.

Several pressure tests were conducted and the test resultsshow a linear dependence between the length of the elementand the pressure rating, which will be higher for smaller openhole sizes due to less swelling. The bonded-to-pipe oil swell-able packers, because of their robust rubber material coupledwith the fold back shoe design, are capable of performing inthe ranges of 1,600 psi/ft to 3,300 psi/ft, Fig. 10.

Fig. 7. Newly developed fit-for-purpose swell packer for multistage fracturingapplications.


ENGINEERED APPROACH FOR OPTIMAL PERFORMANCE OF FRACTURING SLEEVES

Together with the new open hole isolation packer, the develop-ment of a sliding sleeve with an incorporated ball seat designhas been the main contributor to the successful application ofthe MSS technology. The use of incrementally increasing balldiameters — moving from toe to heel — has resulted in thepossibility of deploying a high number of stages. Initially, theincrement sizes typically started at ¼”, and as the demand formore stages increased, the simplest method to meet this de-mand was to reduce the ball increment size to ⅛”. Not satis-fied with this either, the operators in North America pushedfor further increases in stage count and some suppliers starteddeploying systems with 1/16” ball increment sizes. At issue wasthat the operational needs were outpacing the engineering required to fully test and qualify these modifications.

Nonstandard Ball Increment Spacing Sizes

A step backwards was required to properly model and testwhat suppliers had been proposing. It was clear that when theincrement size and the overlap area between the ball and theball seat fell below a certain value, there was a tendency forthe ball to fail or become wedged in the ball seat, thereby pre-venting flow back of the ball. This phenomenon was madeworse by larger balls; the larger the ball, the higher the risk ofthe ball becoming wedged in its seat. Taking an engineered ap-proach to the ball and ball seat interface quickly determinedthat the larger balls needed a larger clearance between the balland ball seat. Simply stated, a thicker metal was needed to beable to withstand the wedging effect; therefore the incrementsize had to be higher than the ⅛” range. For the smaller sizedballs, the increment size could be reduced, and the spacing be-tween the ball sizes could be decreased to less than ⅛” incre-ment sizes. The ultimate achievement was to adopt non-standard increments for the full range of ball sizes, so as to create equal forces between the ball and the ball seat’s interfacefor all sizes, Fig. 11.

Curved Ball Seats

Additionally, with this ball and ball seat interface in mind, sev-eral studies were performed to analyze the stresses acting onthe ball after it contacted the ball seat area. With a conven-tional ball seat, the standard shape on the contact angle is a30° profile. Testing and actual operations showed that this typ-ically created a sharp stress point that either resulted in the ballcracking during the fracturing treatment or the ball becomingwedged in the ball seat itself, Fig. 12. The optimum design wasfound to be a “curved” ball seat, which resulted in a uniformstress distribution across the ball and seat interface, Fig. 13.

Segmented Body for Full Bore Mill-out

CT mill-out of the ball seats has always been a problematicarea, prompting discussion16, 17. Even with the optimum

Fig. 8. Pre-test swell packer with fold back shoes on both ends.

Fig. 9. Post-test swell packer with fold back shoes deployed.

Fig. 10. The graph is validated by actual full scale testing in various hole sizes.

Fig. 11. Ball seat increment calculations and finite element analysis for ball interface optimization.


milling BHA and procedures, failures still occur. In addition tooptimizing the ball seat with a very robust design for the frac-turing operation, it was noted straightaway that the ball seatdesign should also be easy to mill.

The new ball seat has a segmented design that allows forsmooth and simple milling operation. Another notable featureis that the ball seat can be milled out full bore, compared tothe conventional design, which leaves a slither of metal aftermill-out that can easily cause further problems with the CT operation and increases the risk of sticking or damaging theCT pipe, Fig. 14.

MSWP COMPLETION SYSTEM OPERATIONAL EXECUTION

Well-X was drilled and the pilot hole encountered good poros-ity development in reservoir-B, layer B1, with 40 ft true verti-cal depth net pay and 10% average porosity. Further analysisshowed good reservoir quality but limited drainage volume.The existing vertical well was then sidetracked in the minimumstress direction with a horizontal lateral to maximize the reser-voir contact, and it was equipped with a three-stage MSS com-pletion to enhance the well productivity. The open hole MSStechnology to be trial tested on this well was a 4½” MSS sys-tem with swellable packers.

A 5⅞” open hole section of 2,831 ft was drilled without is-sue to 15,443 ft measured depth. An open hole reamer tripwas run prior to running with a 4½” MSS, and one tight spotwas encountered at 12,950 ft to 13,000 ft. The assembly waswashed and reamed without rotation. The 4½” MSS assembly,including a liner hanger system, was smoothly deployed to totaldepth. A 1.700” ball was dropped to flow through the circula-tion valve and the valve was closed at 1,200 psi. With a closedsystem in place, the liner hanger was set at 2,000 psi and therunning tool was released at 3,000 psi. The running tool waspicked up and the liner top packer was set with 80,000 pounds(klb) of slack off. The liner top packer was tested from the annulus side to 3,000 psi for 15 minutes, Fig. 15.

Fig. 12. Conventional ball seat’s high stress points potentially cause cracking or “egging” of the ball.

Fig. 13. Curved ball seat design — uniformly distributed stresses across the ballseat reduce the chance of failure.

Fig. 14. Improved millable design, compared to the conventional design, of the ball seat.


The upper completion string with a tieback seal assemblywas landed in the tubing receptacle. The tubing pressure wasincreased to 8,800 psi. A clear indication was seen that the hy-draulic frac valve had opened, Fig. 16.

The newly opened, unstimulated, internal toe was expected tobe very tight, and that proved to be the case as, at a relativelylow circulation rate of 5 barrels per minute (BPM), a maxi-mum bottom-hole pressure (BHP) of 15,000 psi was reached.Regardless of the lack of injectivity, the instantaneous shut-in

pressure was 600 psi lower than the first injection test, mean-ing that the formation had released pressure due to the previ-ous flow back. The fact that the formation was able to releasepressure from previous flow back shows that all previously in-jected volume had been taken by the reservoir; poroelasticitytherefore was having a significant effect in the near wellborearea, limiting injection rate and volume. A decision was thenmade to spot acid with CT to improve injectivity. Conse-quently, a total of 100 bbl of 20% hydrochloric (HCl) acid

Fig. 15. Geolograph showing sequence of events.


was pumped and over displaced with 70 bbl of treated water.During the displacement, the pressure increased from 5,500 psito 6,200 psi.

Following the end of the first stage, the decision was to pro-ceed with the second stage. A 3” magnesium ball was allowedto free fall in the vertical section for an hour. After an hour,pumps were started at a constant rate of 3 BPM. A clear indi-cation was seen of the ball landing on the seat; the pressure increased from 4,100 psi to 6,100 psi, and then an immediatefall in pressure to 5,200 psi was seen, indicating that the sleevehad been opened and a new zone was available.

Due to the positive opening of the sleeve and the ability to

inject into the formation, a decision was made to perform anacid squeeze with CT. After injection with CT at a rate of 6.5BPM, a decision was made to perform an injection test withthe fracturing equipment. The injection test showed pressurestability at the pumping rate of 20 BPM, which allowed thepossibility of performing an acid fracturing treatment, Fig. 17.Subsequently, 1,900 bbl of treatment fluid, including divertingagent, 28% HCl acid and treated water were pumped.

Overall, the acid injectivity in Stage 2 was very good, typi-cally between 20 BPM and 30 BPM. Stage 1 showed poor in-jectivity with 1 BPM to a maximum of 8 BPM (for a very shortperiod). This is a clear case of compartmentalization being ex-hibited by the swellable packers. If there had been channelingpast the swellable packers, both zones should have exhibitedsimilar injectivity behavior.

CONCLUSIONS

The following conclusions were noted from the performance ofthe new multistage fracturing completion equipment:

• An integrated approach, involving all departments from theoperator side as well as positive communication with theservice company, assisted in making the overall operation acomplete success.

• Thorough full-scale swellable packer testing demonstratedthat the equipment exceeded the operational pressure andtemperature considerations as well as the acid treatmenttype.

• No operational lost time was recorded during thecompletion deployment operation as well as during thestimulation treatment.

• The newly developed and installed swellable packers weresuccessfully able to withstand and compartmentalize thefracturing pressure exerted.

• The hydraulic frac sleeve was successfully opened at thefirst attempt, and a positive indication was recorded. An

Fig. 16. Pressure increased to 8,800 psi and dropped to 7,450 psi before holdingsteady. This gave a clear indication that valve had opened.

Fig. 17. Injectivity test for the newly opened Stage 2.


injectivity test showed a very tight formation across the toesection.

• A successful opening of the ball actuated frac sleeve wasobserved; this was proven by a clear pressure responsewhen the ball landed onto the ball seat and the sleeveopened to the new formation zone.

• The high fracture injection pressure response proved that anew zone was initiated, verified by BHP evaluation duringthe DataFRAC and main acid fracturing treatment.

• The multistage completion equipment was successfullydeployed to the target depth as per all the well objectives.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this arti-cle. Also, the authors would like to recognize Saudi Aramcoand the service company employees who are involved in multi-stage fracturing in Saudi Arabia.

This article was presented at the International PetroleumTechnology Conference, Kuala Lumpur, Malaysia, December10-12, 2014.

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2. Yalavarthi, R., Jayakumar, R., Nyaaba, C. and Rai, R.:“Impact of Completion Design on UnconventionalHorizontal Well Performance,” SPE paper 168673,presented at the Unconventional Resources TechnologyConference, Denver, Colorado, August 12-14, 2013.

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BIOGRAPHIES

Mohammed A. Al-Ghazal is aProduction Engineer at Saudi Aramco.He is part of a team that is responsiblefor gas production optimization in theSouthern Area gas reserves of SaudiArabia. During Mohammed’s careerwith Saudi Aramco, he has led and

participated in several upstream projects, including thoseaddressing pressure control valve optimization, cathodicprotection system performance, venturi meter calibration,new stimulation technologies, innovative wirelinetechnology applications, upgrading of fracturing strategies,petroleum computer-based applications enhancement andsafety management processes development.

In 2011, Mohammed assumed the position of GasProduction HSE Advisor in addition to his productionengineering duties.

In early 2012, Mohammed went on assignment with theSouthern Area Well Completion Operations Department,where he worked as a foreman leading a well completionsite in several remote areas.

As a Production Engineer, Mohammed played a criticalrole in the first successful application of several high-endtechnologies in the Kingdom’s gas reservoirs.

In 2010, Mohammed received his B.S. degree withhonors in Petroleum Engineering from King FahdUniversity of Petroleum and Minerals (KFUPM), Dhahran,Saudi Arabia.

He has also authored and coauthored several Society ofPetroleum Engineers (SPE) papers and technical journalarticles as well as numerous in-house technical reports.Additionally, Mohammed served as a member of theindustry and student advisory board in the PetroleumEngineering Department of KFUPM from 2009 to 2011.

As an active SPE member, he serves on the Productionand Operations Award Committee.

Recently, he won the best presentation award at theproduction engineering session of the 2013 SPE YoungProfessional Technical Symposium.

participated in severa

Mohammed is currently pursuing an M.S. degree inEngineering at the University of Southern California, LosAngeles, CA.

Saad M. Al-Driweesh is a GeneralSupervisor in the Southern AreaProduction Engineering Department,where he is involved in gas productionengineering, well completion, andfracturing and stimulation activities.

Saad is an active member of theSociety of Petroleum Engineers (SPE), where he has chairedseveral technical sessions in local, regional andinternational conferences. He is also the 2013 recipient ofthe SPE Production and Operations Award for the MiddleEast, North Africa and India region. In addition, Saadchaired the first Unconventional Gas Technical Event andExhibition in Saudi Arabia.

He has published several technical articles addressinginnovations in science and technology. Saad’s main interestis in the field of production engineering, includingproduction optimization, fracturing and stimulation, andnew well completion applications. He has 26 years ofexperience in areas related to gas and oil productionengineering.

In 1988, he received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

Mustafa R. Al-Zaid is a GasProduction Engineer with SaudiAramco’s Southern Area ProductionEngineering Department. He is part ofa gas production optimization team,which is responsible for wellcompletion, stimulation and fracturing

activities in the Ghawar field. Mustafa has designed and executed several critical

rigless well interventions, including wireline operations andcoiled tubing stimulation and cleaning in the Ghawar field.

In 2010, he received his B.S. degree in PetroleumEngineering from the University of Adelaide, Adelaide,Australia. Mustafa has also successfully completed severaltechnical courses relating reservoir management, wellcompletion and production engineering at Saudi Aramco’sUpstream Professional Development Center, Dhahran,Saudi Arabia.

Fadel A. Al-Ghurairi is a PetroleumEngineering Consultant and TechnicalSupport Unit Supervisor working ongas fields. He has 24 years ofexperience in production and reservoirengineering. In the last 12 years, Fadelhas specialized in stimulation and

fracturing of deep gas wells.In 1988, he received his B.S. degree in Petroleum

Engineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

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f t i f df


greater value can be created at lower costs. In this model, dif-ferent partners can work on different parts of the challenge andshare expenses for the research and prototypes, deriving differentbenefits as appropriate. A significant argument for such a net-work model is that most entrepreneurs or SMEs do not havethe needed internal technological competencies or resources.The vital strategic components of intellectual capital8, 9 forSMEs or entrepreneurs — talent, teams and technology (the 3Ts)7, 8 — often are not fully explored because of resource lim-its. The new IN model may allow participants to overcome thislimit by leveraging the commercial value of technologies thatexist in other organizations or that had been co-developed byteaming with talented partners.

Second, multidisciplinary and cross-industry collaborationaround a common challenge with multiple objectives enhancescreativity among the partners involved. Although a rarely usedtechnique among SMEs, this approach can spark the search formore innovative products, services and related concepts.

Third, the partnering of SMEs and/or entrepreneurial organ-izations with large companies may benefit from the use of“spillover technology” that is not necessarily relevant for largecompanies, but might be of interest to smaller ones, entrepre-neurs and other vested groups. The concept of OI cannot beapplied to capture the typical large company benefits — suchas sharing costs and risks, faster product introduction, etc. —for entrepreneurs or SMEs. Instead, SMEs historically have en-gaged (or often have been forced into) innovation via a net-work as a consequence of major shifts in their business model,whether to seize new business opportunities and/or to boostprofitability, or merely to survive. When they confront such ashift, their limited financial and human resources and theirlack of technological capabilities often force them to look fordifferent types of innovation partners.

The key to success for technology development or economicdevelopment via innovation depends on (1) Identifying thestrategic drivers to address the greatest needs or challenges forall, (2) Engaging stakeholders and obtaining their buy-ins, (3)Implementing or conducting an approach to the challenge in themost effective manner to derive maximum benefit for all partnersand stockholders, and finally, (4) Deploying solutions by engag-ing partners and collaborators. Managing relationships with in-dividual partners and organizing the overall network of diverse

The concept of open innovation (OI) became popular duringthe last decade. OI allowed companies to leverage globalsourcing to create business value, keeping in mind that goodideas are widely distributed since not all of the smartest peoplein the world work for any single company. Chesbrough(2003)1 introduced the OI term to address the needs of mostlytechnology-focused R&D departments in large companies thatwere “closed” and highly secretive. It has long been recognizedthat opening the doors of large companies to outside input andencouraging an exchange of information will stimulate internalinnovation2-6. The OI practices of large manufacturing compa-nies, such as GE, P&G, Philips, Xerox and IBM, are widelydocumented7. As the goal of OI is to source the best innovationsfrom anywhere in the world, large companies seeking to addressa specific challenge and to deploy internal solutions externallydeliberately introduced OI practices. Can this concept be ex-tended to smaller entities, such as small- and medium-sized enterprises (SMEs) and entrepreneurs? Can the concept of OIbe applied to encourage regional development by supportinglocal entrepreneurship and venturing?

In a paradigm shift, Saudi Aramco Entrepreneurship (AEC)has initiated an innovation competition with multiple goals di-rected at addressing the needs of large organizations, SMEs andindividual entrepreneurs, and identifying venture opportunityneeds. The new business model, via the innovation competition,strives to create value through global participation.

Large companies have successfully used innovation competi-tions as the primary avenue to pursue OI to fill their internalR&D voids. In the paradigm shifted model, coined “InnovationNetwork” (IN), innovation can be viewed from the perspectiveof not only large companies, but also numerous types/sizes oforganizations with diverse roles and needs. In this model, OIcan become relevant to entrepreneurs, startups and the organi-zations that support them as well as other stakeholders. Smallcompanies can benefit in different ways from an innovationcompetition if it is designed effectively. This article highlightsthe “why” and “how” AEC with other stakeholders has usedIN by launching a global competition.

First, cost savings and control can be a significant benefit.When innovation competition is tightly restricted to one company, only the sponsor extracts the benefits. When organiza-tions innovate “jointly” via IN through a global competition, a

Deploying Global Competition by InnovationNetwork for Empowering Entrepreneurship,Venturing and Local Business Development:A Case Study — Desalination UsingRenewable EnergyAuthor: Dr. M. Rashid Khan


innovation partners is critical to success, since collaborative in-novation is easier with partners of similar size and ambitions.This careful management of relations and needs is paramountand is more challenging than when an OI model is focused onone goal and a single company. A case study of innovation thataddressed a regional challenge with global input and an addedgoal to further entrepreneurship is provided in this article, withcareful consideration of all four elements listed above.

To help Saudi Arabia meet its ever-growing need for potablewater and to foster a culture of technology-based entrepreneur-ship in the Kingdom, the AEC and GE in April 2014 launcheda global competition in the area of seawater desalination, witha particular focus on using renewable energy. What is the linkbetween innovation and entrepreneurship? Why did AEC,which is focused on regional business development, get in-volved in such a global topic? What are the justifications forAEC’s co-sponsorship of this global innovation competition?

First, the desalination topic addresses one of the greatesttechnical and business challenges of our time, and addressingand fulfilling a need is fundamental to entrepreneurship devel-opment. Saudi Arabia is considered to be among the poorestcountries in the world in terms of natural renewable water re-sources, and it depends upon energy-intensive water desalinationplants and its rapidly depleting groundwater reserves to meetits fast-growing water needs. The Kingdom is the world’slargest producer of desalinated water, which meets over 70% ofits present drinking water needs. Over 50 cities and distributioncenters in Saudi Arabia receive their water from these plants. Thestate-owned Saline Water Conversion Corporation (SWCC)operates 36 desalination stations, and independent power andwater producers supplement these. SWCC would like to see agreater participation by the private sector, and therefore, viewsfurther development as an opportunity for entrepreneurs andlocal venturing. Using this initiative of global competition by IN,the AEC hopes not only to solicit innovative solutions but also todevelop and deploy those solutions here in the Kingdom throughcollaboration between both national and global innovators.Therefore, the innovation competition was conceived withbroader perspectives in mind, and the challenge was accord-ingly developed with partners and stakeholders to address thegreatest technical need of the region, engaging SWCC, KingAbdulaziz City for Science and Technology (KACST) and allkey local universities. In the formulation of the competition,many avenues were explored, and many service providers wereconsidered. Partnership with GE appeared to be the most eco-nomic and efficient way to achieve the most desirable results.The ultimate scope of the challenge developed by AEC, whichserved as the “main hub” of the innovation network, addressedthe somewhat competing needs of all partners/stakeholders.

The competition has attracted 108 proposals from globalexperts with multidisciplinary backgrounds with respect to geographic distribution (32 countries), organization type andexperience (with combined input reflecting nearly 200patents/peer-reviewed publications by over 100 Ph.D.s and

other advanced professionals). Based on the initial assess-ments, many proposals address the needs of the stakeholders(SWCC, GE, Saudi Aramco, Saudi Aramco Energy Ventures(SAEV), AEC and in-Kingdom entrepreneurs). Subsequent dia-logues among technology leaders in this strategic area may allowSAEV, SWCC, AEC and others to develop partnerships withglobal innovative companies having cutting-edge solutions forpossible venturing and local deployment.

Second, in Saudi Arabia, significant investment funding hasbeen allocated to increasing potable water, creating opportunitiesfor entrepreneurship and venturing. As the largest user of de-salination processes and technology in the world, Saudi Arabia isprojected to spend about $50 billion on seawater desalinationtechnologies in the coming decade and to invest around $100billion in solar energy. Current desalination techniques are energyintensive. To fuel desalination, Saudi Arabia is burning theequivalent of 1.5 million barrels of oil per day of precious fuels.An increase in energy efficiency and/or a reduction in energyconsumption is the key to ensuring that the Kingdom receivesthe most value for its natural resources — value that can be usedto develop the Kingdom and its people. As a result, the network-based initiative by AEC received significant support at the outsetfrom SWCC, the main proponent for the Kingdom’s desalination.

Fig. 1. Number of patents filed worldwide related to “Osmotic Derived MembraneProcess,” just one of many types of desalination methods commercially used.Source: International Desalination Report (IDS), September 2014.

Fig. 2. The submissions came from 32 countries with 108 proposals, the largestnumber from the U.S. and the second largest input from Saudi Arabia.


Third, successful entrepreneurs welcome the best conceptsthat address a critical need no matter where the solutions comefrom. As a result, the AEC charter encourages AEC to engagein activities in or outside Saudi Arabia in realizing its key objective, that of promoting entrepreneurship. According tomany experts — as described in many textbooks — an entre-preneur is a person who converts an innovation into a business,no matter where the innovation originates. Khalid A. Al-Falih7,president and CEO of Saudi Aramco, routinely links entrepre-neurship with innovation. Useful technology and know-howtoday is widely distributed and is increasing in a rapid manner,Fig. 1, and no individual organization — no matter how capableor how big — can innovate effectively on its own. Despite beingthe first one organized by Saudi Aramco, the global innovationcompetition generated a large number of quality responses, in-cluding a sizeable number from Saudi Arabia. It is clear thatthe Kingdom and the company can save energy and financialresources by applying creative new technologies and processes.The largest number of country-based submissions came fromthe U.S. (38 submissions), followed by Saudi Arabia (nine sub-missions), Fig. 2. The proposals received careful review bymultidisciplinary teams in SWCC, GE and Saudi Aramco toidentify those solutions that best address the critical needs ofthe region and that can be readily deployed via entrepreneurshipand venturing in Saudi Arabia, in addition to fulfilling the mis-sion of SWCC and GE.

SUMMARY

Entrepreneurship is always heightened by new technologies.The innovation competition generated many concepts of valuefor all of the parties concerned. The broader perspective of in-novation so defined can be used to extract multiple benefitsfrom larger organizations, such as SWCC, Saudi Aramco andGE, as well as from the smaller entities such as local entrepre-neurs, SMEs and those engaged in local venture development.The broader perspective of the IN model should be far moreeffective than traditional OI. That is because the IN incorpo-rates the perspective of regional innovation as involving manydiverse players, including local research centers for fundamen-tal, basic and applied research; business ecosystems for bothestablished companies and startups; government institutionsand entrepreneurs; and agents of technology transfer andstartup incubators.

Saudi Arabia is in need of cost-effective and energy-effectivetechnologies for producing desalinated water. In the past, waterproduction and security of supply drove technology selection.Because energy costs were low, proven, established technologiestended to be preferred over innovative solutions. This globalcompetition, which focuses on the use of abundant renewableenergy — such as solar — brings greater innovation to thiscritical area, and there are plans to introduce efficient newtechnologies in stations nearing the end of their life span, bothto extend their productive life and to test new technologies.

Applying the newer model, global innovation has the potentialto present alternatives from key experts around the world toexpand the technology options for Saudi Arabian organiza-tions, which they can then develop, leverage and deploy in thefuture, empowering regional entrepreneurship.

Finally, the network model of innovation conducted via aglobal competition not only will assist the stakeholders, suchas SWCC, Saudi Aramco and GE, but will also enable venturedevelopment and entrepreneurship. The contest was developedkeeping localization in mind in collaboration with the key localstakeholders, such as SWCC, KACST and others. As an exam-ple of support, SWCC offered to locally facilitate the testingand deployment of those technologies with high potential, andto serve as a key stakeholder for the initiative.

Desalination and renewables are among the greatest challengesfor the Kingdom, as defined by KACST, following the directiveof the Custodian of the Two Holy Mosques King ‘Abd Allahibn ‘Abd Al-’Aziz Al Sa’ud. Therefore, the innovative conceptsgained from the competition can be localized to create high-value new local businesses and high value jobs in Saudi Arabia.

REFERENCES

1. Chesbrough, H.: Open Innovation, Harvard BusinessSchool Press, Cambridge, MA, 2003, 227 p.

2. Tilton, J.: International Diffusion of Technology: The Caseof Semiconductors, Brookings Institute, Washington, D.C.,1971, 183 p.

3. Allen, T.J.: Managing Flow of Technology, The MIT Press,Cambridge, MA, 1977, 334 p.

4. Tidd, J.: “Conjoint Innovation: Building a Bridge betweenInnovation and Entrepreneurship,” International Journal ofInnovation Management, Vol. 18, No. 1, February 2014.

5. Rothwell, R. and Zegveld, W.: Reindustrialization andTechnology, Longman, London (Harlow), 1985, 282 p.

6. Khan, M.R.: “Some Insights into Embracing an InnovationCompetition to Identify Breakthrough Technologies orProcesses,” Saudi Aramco Journal of Technology, Fall 2010.

7. “MIT and Saudi Aramco Augment Existing Collaboration:More Energy Research,” MOU signed by MIT and SaudiAramco, June 18, 2012. http://mitei.mit.edu/news/mit-and-saudi-aramco-augment-existing-collaboration.

8. Khan, M.R. and Germeraad, P.: “Management ofInnovation and Intellectual Capital: The Concept of ThreeT’s for Growth and Sustainability for an Organization anda Nation,” Les Nouvelles, March 2011, pp. 26-38.

9. Khursani, S.A., Bazuhair, O.S. and Khan, M.R.: “Strategyfor the Rapid Transformation of Saudi Arabia byLeveraging Intellectual Capital and KnowledgeManagement,” Saudi Aramco Journal of Technology,Winter 2011.


BIOGRAPHY

Dr. M. Rashid Khan is Head ofIntellectual Property and Innovationfor Saudi Aramco Entrepreneurship,where he launched the first GlobalInnovation Competition for SaudiAramco. Previously, he served as theDeputy Director of the Technology

Management Program of Engineering Services and was amember of the Intellectual Assets and InnovationManagement Group from the onset of these programs.Rashid shaped the first Intellectual Property (IP) policy forKing Abdullah University of Science and Technology(KAUST), and defined the IP strategy in executing severaltechnology transfer agreements, while also serving as thekey technical reviewer.

He has extensive work experience in upstream,downstream and other diverse areas of the oil and gasindustry. Rashid has served as a “Distinguished Lecturer”for the Society of Petroleum Engineers (SPE) and presentedmany invited lectures, including at Harvard and MIT. Heserved as a mentor for the MIT Energy Competition andLicensing Executive Business Competition, and taught acourse on patent monetization at MIT. Rashid also taught acourse on Entrepreneurship at King Fahd University ofPetroleum and Minerals (KFUPM).

He received Texaco’s highest technical award forcreativity. Rashid also received the American ChemicalSociety Texaco Research Award. Additionally, he served asa Technical Advisor to the U.S. White House; was anAdjunct Professor for Vassar College, Poughkeepsie, NY;and served in the United Nations Development Program(UNDP). Rashid has around 30 patent awards and haspublished over 200 journal papers. He has edited orauthored six books in the areas of energy, environment,innovation, IP and business development.

Rashid received his M.S. in Environmental Engineeringfrom Oregon State University, Corvallis, OR, in 1979 andhis Ph.D. degree in Energy and Fuels Engineering fromPennsylvania State University, University Park, PA, in 1984.

He was recognized as a “Distinguished Fellow” by thePresident of Licensing Executive Society. Rashid is aCertified Patent Licensing Professional.

Management Progra


2014 SAUDI ARAMCO PATENTS GRANTED LIST

CLAY ADDITIVE FOR REDUCTION OF SULFUR INCATALYTICALLY CRACKED GASOLINE

Granted Patent: U.S. 8,623,199, Grant Date: January 7, 2014Abdennour Bourane, Omer R. Koseoglu, Musaed Al-Ghrami,Christopher Dean, Mohammed A. Siddiqui and Shakeel Ahmed

Summary

The patent relates to the reduction of sulfur in gasolineproduced in a fluid catalytic cracking process, and moreparticularly, to a method and sulfur reduction additivecomposition for use in the fluid catalytic cracking process.

HYDRATED NIOBIUM OXIDE NANOPARTICLECONTAINING CATALYSTS FOR OLEFIN HYDRATION

Granted Patent: U.S. 8,629,080, Grant Date: January 14, 2014Abdennour Bourane, Stephan R. Vogel and Wei Xu

Summary

The patent relates to a catalyst and method of preparing acatalyst for olefin hydration. More specifically, the inven-tion relates to a catalyst and method of preparing a cata-lyst wherein the catalyst includes amorphous or crystallinenanoparticles of hydrated niobium oxide, niobium oxo-sulfate, niobium oxo-phosphate or mixtures thereof foruse in the hydration of olefins.

METHOD FOR PREPARING POLYPROPYLENE FILMSHAVING IMPROVED ULTRAVIOLET RADIATIONSTABILITY AND SERVICE LIFE

Granted Patent: U.S. 8,629,204, Grant Date: January 14, 2014Ahmed Basfar, Khondoker Ali, Milind M. Vaidya and Ahmed Bahamdan

Summary

The patent relates to a polyolefin resin and articles pre-pared from the polyolefin resin. More specifically, the invention relates to a polypropylene resin exhibiting im-proved ultraviolet radiation stability and articles preparedtherefrom.

PROCESS FOR CATALYTIC HYDROTREATING OFSOUR CRUDE OILS

Granted Patent: U.S. 8,632,673, Grant Date: January 21, 2014Stephane Kressmann, Raheel Shafi, Esam Hamad and Bashir M. Dabbousi

Summary

The patent relates to a pre-refining process for the desulfu-rization of sour crude oils using a catalytic hydrotreating

process that includes permutable reactors and that is capa-ble of operating at moderate temperature and pressurewith reduced hydrogen consumption.

DETERMINATION OF ROCK MECHANICS FROMAPPLIED FORCE TO AREA MEASURES WHILESLABBING CORE SAMPLES

Granted Patent: U.S. 8,635,026, Grant Date: January 21, 2014Mohammad Ameen

Summary

The patent relates to rock material characterization, andin particular, to characterization of mechanical propertiesof formation rock from hydrocarbon reservoirs for geo-logical and engineering purposes, such as design and planning of well completion, well testing and formationstimulation.

METHOD FOR REMOVING MERCURY FROM AGASEOUS OR LIQUID STREAM

Granted Patent: U.S. 8,641,890, Grant Date: February 4, 2014Feras Hamad, Ahmed A. Bahamdan, Abdulaziz Al-Mulhim,Ayman Rashwan and Bandar A. Fadhel

Summary

The patent relates to an apparatus and method for remov-ing mercury or mercury containing compounds from fluids, e.g., liquids, gases and gaseous condensates. Moreparticularly, it relates to the use of porous membranes andscrubbing solutions, which when used in tandem removemercury from the aforementioned fluids.

RECOVERY OF HEAVY OIL THROUGH THE USE OFMICROWAVE HEATING IN HORIZONTAL WELLS

Granted Patent: U.S. 8,646,524, Grant Date: February 11, 2014Khaled Al-Buraik

Summary

The patent relates to a method of extracting and recover-ing subsurface sour crude oil deposits. More specifically,the method employs microwave radiation and the perme-ability enhancement of reservoir rocks due to fracture byselective heating and due to the creation of critical and supercritical fluids in the subsurface area.

SYSTEM AND METHOD FOR IMPROVEDCOORDINATION BETWEEN CONTROL ANDSAFETY SYSTEMS

Granted Patent: U.S. 8,649,888, Grant Date: February 11, 2014Abdelghani A. Daraiseh and Patrick S. Flanders


Summary

The patent relates to regulatory control systems and safetyshutdown systems, and methods for monitoring and con-trolling field devices used with commercial and industrialprocesses. In particular, it relates to systems and methodsfor improved coordination between control and safety systems.

CATHODIC PROTECTION ASSESSMENT PROBE

Granted Patent: U.S. 8,652,312, Grant Date: February 18, 2014Darrell Catte

Summary

The patent relates to an apparatus and method for usewith a corrosion monitoring and/or mitigation system.More specifically, the invention relates to an apparatusand method for monitoring cathodic protection while sup-plying cathodic protection power to an object being pro-tected. Yet more specifically, the invention relates to asystem for determining electrolyte corrosivity and opti-mum site-specific cathodic protection operating levels.

SULFUR STEEL-SLAG AGGREGATE CONCRETE

Granted Patent: U.S. 8,652,251, Grant Date: February 18, 2014Mohammed Al-Mehthel, Saleh Al-Idi, Mohammed Maslehuddin,Mohammed R. Ali and Mohammed S. Barry

Summary

The patent relates to a composition and method for dis-posing of sulfur by using it to produce a sulfur-based concrete.

INTEGRATED HYDROTREATING AND OXIDATIVEDESULFURIZATION PROCESS

Granted Patent: U.S. 8,658,027, Grant Date: February 25, 2014Omer R. Koseoglu and Abdennour Bourane

Summary

The patent relates to desulfurization of hydrocarbonstreams, and in particular, to a system and process for in-tegrated hydrotreating and oxidative desulfurization ofhydrocarbon streams to produce reduced sulfur contenthydrocarbon fuels.

SLIDING STAGE CEMENTING TOOL

Granted Patent: U.S. 8,657,004, Grant Date: February 25, 2014Shaohua Zhou

Summary

The patent relates to an apparatus for use while completing

a subterranean hydrocarbon producing well. More specifi-cally, the invention relates to an apparatus for the stagingof cement between the casing and a wellbore.

CATALYTIC PROCESS FOR DEEP OXIDATIVEDESULFURIZATION OF LIQUID TRANSPORTATIONFUELS

Granted Patent: U.S. 8,663,459, Grant Date: March 4, 2014Farhan M. Al-Shahrani, Gary Martinie, Tiancun Xiao andMalcolm Green

Summary

The patent relates to novel catalysts, systems andprocesses for the reduction of the sulfur content of liquidhydrocarbon fractions of transportation fuels, includinggasoline and diesel fuels, to about 10 ppm or less by anoxidative reaction.

ECONOMICAL HEAVY CONCRETE WEIGHTCOATING FOR SUBMARINE PIPELINES

Granted Patent: U.S. 8,662,111, Grant Date: March 4, 2014Mohammed Al-Mehthel, Bakr Hammad, Alaeddin Al-Sharif,Mohammed Maslehuddin and Mohammed Ibrahim

Summary

The patent relates to the field of submarine pipelines. Inparticular, the invention is directed to an economicalheavy concrete weight coating used to keep the submarinepipeline submerged below the surface of the water.

MACHINES, COMPUTER PROGRAM PRODUCTSAND COMPUTER-IMPLEMENTED METHODSPROVIDING AN INTEGRATED NODE FOR DATAACQUISITION AND CONTROL

Granted Patent: U.S. 8,667,091, Grant Date: March 4, 2014Soliman M. Almadi, Soliman A. Al-Walaie and Tofig A. Al-Dhubaib

Summary

The patent relates to automated industrial processes. Inparticular, the invention relates to the control of and theacquisition of data from, remote and in-plant subsystemsin automated industrial processes.

PLUGGING THIEF ZONES AND FRACTURES BY INSITU AND IN-DEPTH CRYSTALLIZATION FORIMPROVING WATER SWEEP EFFICIENCY OFSANDSTONE AND CARBONATE RESERVOIRS

Granted Patent: U.S. 8,662,173, Grant Date: March 4, 2014Xianmin Zhou and Yun C. Chang


Summary

The patent relates to compositions and methods for treat-ing subterranean formations. More specifically, the inven-tion relates to compositions and methods for pluggingthief zones and fractures in subterranean formations.

SUPER-RESOLUTION FORMATION FLUID IMAGING

Granted Patent: U.S. 8,664,586, Grant Date: March 4, 2014Howard K. Schmidt

Summary

The patent relates to imaging subsurface structures, partic-ularly hydrocarbon reservoirs and fluids therein; it relatesmore particularly to cross-well and borehole to surfaceelectromagnetic (BSEM) surveying.

BUOYANT PLUG FOR EMERGENCY DRAIN INFLOATING ROOF TANK

Granted Patent: U.S. 8,668,105, Grant Date: March 11, 2014Nassir S. Al-Subaiey

Summary

The patent relates to floating roofs for storage tanks thatcontain volatile fluid, and more particularly, to an emer-gency drain valve for water accumulated atop a doubledeck roof.

WELL SYSTEM WITH LATERAL MAIN BORE ANDSTRATEGICALLY DISPOSED LATERAL BORES ANDMETHOD OF FORMING

Granted Patent: U.S. 8,672,034, Grant Date: March 18, 2014Fahad M. Al-Ajmi and Ahmed H. Alhuthali

Summary

The patent relates to a subterranean hydrocarbon produc-ing well system. More specifically, the invention relates toa well system having a main bore that extends above aproducing formation with lateral bores that depend fromthe main bore and intersect the producing formation.

PIPELINE LEAK DETECTION AND LOCATIONSYSTEM THROUGH PRESSURE AND CATHODICPROTECTION SOIL

Granted Patent: U.S. 8,682,600, Grant Date: March 25, 2014Pablo D. Genta

Summary

The patent relates to the detection and location of fuelleakages occurring in underground jet fuel piping systemsof the type employed at civil airports and military air

bases. More specifically, it relates to providing continuousmonitoring for leaks and pressure losses in fuel pipelines,as well as providing status indications for, and control of,jet fuel supply valves, isolation valves, jet fuel pumps andother instrumentation in jet fuel piping systems.

BOREHOLE TO SURFACE ELECTROMAGNETICTRANSMITTER

Granted Patent: U.S. 8,680,866, Grant Date: March 25, 2014Alberto F. Marsala, Mohammad Al-Buali, Zhanxiang He and Tang Biyan

Summary

The patent relates to an electromagnetic energy source ortransmitter for borehole to surface electromagnetic survey-ing and mapping of subsurface formations.

ZERO LEAKOFF GEL

Granted Patent: U.S. 8,684,081, Grant Date: April 1, 2014Saleh Al-Mutairi, Ali Al-Aamri, Khalid Al-Dossary and Mubarak Al-Dhufairi

Summary

The patent relates to a silicate gel composition formed insitu and its method of use. More specifically, it relates to asilicate gel composition that forms in a wellbore and amethod of diverting treatment fluid in a wellbore.

METHODS FOR PERFORMING A FULLYAUTOMATED WORKFLOW FOR WELLPERFORMANCE MODEL CREATION ANDCALIBRATION

Granted Patent: U.S. 8,688,426, Grant Date: April 1, 2014Ahmad Al-Shammari

Summary

The patent relates to oil and gas recovery. In particular, itrelates to the optimization of production and injectionrates, and more specifically to systems, program productand methods that provide improved well performancemodeling, building and calibration.

WELLBORE PRESSURE CONTROL DEVICE

Granted Patent: U.S. 8,689,892, Grant Date: April 8, 2014Mohamed N. Noui-Mehidi

Summary

The patent relates to an apparatus and method for manag-ing pressure in a wellbore. More specifically, the inventionrelates to the use of swirling fluids to maintain a wellboreat a desired pressure.


CONVERTING HEAVY SOUR CRUDE OIL/EMULSION TO LIGHTER CRUDE OIL USINGCAVITATIONS AND FILTRATION-BASED SYSTEMS

Granted Patent: U.S. 8,691,083, Grant Date: April 8, 2014M. Rashid Khan

Summary

The patent relates to the conversion of heavier sulfur-con-taining crude oil into lighter crude oil with lower sulfurcontent and lower molecular weight than the originalcrude oil.

SOUR GAS AND ACID NATURAL GAS SEPARATIONMEMBRANE PROCESS BY PRE-REMOVAL OFDISSOLVED ELEMENTAL SULFUR FOR PLUGGINGPREVENTION

Granted Patent: U.S. 8,696,791, Grant Date: April 15, 2014Milind M. Vaidya, Jean-Pierre Ballaguet, Sebastien Duval andAnwar Khawajah

Summary

The patent relates to methods for removing sulfur fromgas streams prior to sending the gas streams to gas separa-tion membranes.

SIMULTANEOUS WAVELET EXTRACTION ANDDECONVOLUTION IN THE TIME DOMAIN

Granted Patent: U.S. 8,705,315, Grant Date: April 22, 2014Saleh Al-Dossary and Jinsong Wang

Summary

The patent relates to seismic data processing and moreparticularly, to wavelet extraction and deconvolution during seismic data processing.

METHODS FOR MANAGING CONTRACTPROCUREMENT

Granted Patent: U.S. 8,706,569, Grant Date: April 22, 2014Hisham Al-Abdulqader, Ammar Al-Mubarak and Udai Al-Mulla

Summary

The patent relates to automated business transaction sys-tems, in particular to contract management systems. Morespecifically, this patent relates to a system, program prod-uct and methods of facilitating contract procurement andcontract management through an online contract procure-ment and management website.

PIPELINE PIG WITH INTERNAL FLOW CAVITY

Granted Patent: U.S. 8,715,423, Grant Date: May 6, 2014Ali Al-Mousa

Summary

The patent relates to pipeline pigs used in the inspection ofpipelines.

PROCESS FOR OXIDATIVE CONVERSION OFORGANOSULFUR COMPOUNDS IN LIQUIDHYDROCARBON MIXTURES

Granted Patent: U.S. 8,715,489, Grant Date: May 6, 2014Gary D. Martinie, Farhan M. Al-Shahrani and Bashir M. Dabbousi

Summary

The patent relates to the conversion of organosulfur com-pounds in liquid hydrocarbon mixtures, and more particu-larly, their conversion by catalytic oxidation.

SLIDING STAGE CEMENTING TOOL AND METHOD

Granted Patent: U.S. 8,720,561, Grant Date: May 13, 2014Shaohua Zhou

Summary

The patent relates to an apparatus for use while complet-ing a subterranean hydrocarbon producing well. Morespecifically, the invention relates to an apparatus for thestaging of cement between the casing and a wellbore.

ASPHALT COMPOSITIONS WITH SULFURMODIFIED POLYVINYL ACETATE (PVAC)

Granted Patent: U.S. 8,721,215, Grant Date: May 13, 2014Mohammed Al-Mehthel, Saleh Al-Idi, Ibnelwaleed Hussein,Hamad Al-Abdulwahhab and Mohammed Suleiman

Summary

The patent relates to asphalt compositions containing as-phalt and sulfur modified polyvinyl acetate polymers hav-ing improved properties relative to unmodified polyvinylacetate polymers.

WASTEWATER TREATMENT PROCESS INCLUDINGIRRADIATION OF PRIMARY SOLIDS

Granted Patent: U.S. 8,721,889, Grant Date: May 13, 2014William Conner, Osama I. Fageeha and Thomas Schultz

Summary

The patent relates to a system and method for wastewatertreatment.


PRODUCTION OF SYNTHESIS GAS FROM SOLVENTDEASPHALTING PROCESS BOTTOMS IN AMEMBRANE WALL GASIFICATION REACTOR

Granted Patent: U.S. 8,721,927, Grant Date: May 13, 2014Omer R. Koseoglu

Summary

The patent relates to processes for the partial oxidation ina membrane wall gasification reactor of heavy bottoms,which can also contain waste materials, recovered from asolvent deasphalting unit operation to produce a highvalue synthesis gas.

SULFUR MODIFIED ASPHALT FOR WARM MIXAPPLICATIONS

Granted Patent: U.S. 8,722,771, Grant Date: May 13, 2014Milind Vidya, Anwar H. Khawajah, Rashid M. Othman andLaurand Lewandowski

Summary

The patent relates to an asphalt concrete mixture, an as-phalt binder composition and methods of preparing theasphalt concrete mixture.

WELLHEAD HIPS WITH AUTOMATIC TESTING ANDSELF-DIAGNOSTICS

Granted Patent: U.S. 8,725,434, Grant Date: May 13, 2014Patrick S. Flanders

Summary

The patent relates to a method and an apparatus for theoperation and testing of a high integrity protection system(HIPS) connected to a wellhead pipeline system.

APPARATUS AND METHODS FOR ENHANCEDWELL CONTROL IN SLIM COMPLETIONS

Granted Patent: U.S. 8,727,016, Grant Date: May 20, 2014Mohamed N. Noui-Mehidi and Jinjiang Xiao

Summary

The patent relates to well control of hydrocarbon wells.More particularly, the invention relates to well control ofa slim-hole well.

CLUSTER 3D PETROPHYSICAL UNCERTAINTYMODELING

Granted Patent: U.S. 8,731,891, Grant Date: May 20, 2014Roger R. Sung and Khalid S. Al-Wahabi

Summary

The patent relates to computerized simulation of

hydrocarbon reservoirs in the earth that have been mod-eled as a three-dimensional grid of cells. In particular, itrelates to the determination of reservoir attributes orproperties on a cell-by-cell basis for the individual cells inthe reservoir model.

SYSTEMS AND PROGRAM PRODUCT FORPERFORMING A FULLY AUTOMATED WORKFLOWFOR WELL PERFORMANCE MODEL CREATIONAND CALIBRATION

Granted Patent: U.S. 8,731,892, Grant Date: May 20, 2014 Ahmad Al-Shammari

Summary

The patent relates to oil and gas recovery, in particular tothe optimization of production and injection rates. Morespecifically, it relates to systems, program product andmethods that provide improved well performance model-ing, building and calibration.

INDUCING FLOW BACK OF DAMAGING MUD-INDUCED MATERIALS AND DEBRIS TO IMPROVEACID STIMULATION OF LONG HORIZONTALINJECTION WELLS IN TIGHT CARBONATEFORMATIONS

Granted Patent: U.S. 8,733,443, Grant Date: May 27, 2014Ali A. Al-Taq

Summary

The patent relates to a method of conditioning a long hor-izontal open hole water injection well in a tight formationprior to acid stimulation to improve the contact of theacid with the rock as well as the penetration of the acidicmaterials into the reservoir rock, and thereby enhancingthe permeability of the formation and the flow rate of theinjected water.

DETERMINATION OF ANGLE OF INTERNALFRICTION OF FORMATION ROCK WHILE SLABBINGCORE SAMPLES

Granted Patent: U.S. 8,738,294, Grant Date: May 27, 2014Mohammed S. Ameen

Summary

The patent relates to rock material characterization, andin particular, to the characterization of the mechanicalproperties of formation rock from hydrocarbon reservoirsfor geological and engineering purposes, such as designand planning of well completion, well testing and forma-tion stimulation.


INTEGRATED DESULFURIZATION AND DENITRI-FICATION PROCESS INCLUDING MILD HYDRO-TREATING AND OXIDATION OF AROMATIC-RICHHYDROTREATED PRODUCTS

Granted Patent: U.S. 8,741,127, Grant Date: June 3, 2014 Omer R. Koseoglu, Abdennour Bourane, Farhan M. Al-Shahraniand Emad Al-Shafi

Summary

The patent relates to integrated oxidation processes to ef-ficiently reduce the sulfur and nitrogen content of hydro-carbons to produce fuels having reduced sulfur andnitrogen levels.

INTEGRATED DESULFURIZATION AND DENITRI-FICATION PROCESS INCLUDING MILD HYDRO-TREATING OF AROMATIC-LEAN FRACTION ANDOXIDATION OF AROMATIC-RICH FRACTION

Granted Patent: U.S. 8,741,128, Grant Date: June 3, 2014 Omer R. Koseoglu, Abdennour Bourane, Farhan M. Al-Shahraniand Emad Al-Shafi

Summary

The patent relates to integrated oxidation processes to ef-ficiently reduce the sulfur and nitrogen content of hydro-carbons to produce fuels having reduced sulfur andnitrogen levels.

METHODS OF PREPARING LIQUID BLENDS FORBUILDING CALIBRATION CURVES FOR THE EFFECTOF CONCENTRATION ON LASER-INDUCEDFLUORESCENCE INTENSITY

Granted Patent: U.S. 8,742,340, Grant Date: June 3, 2014Ezzat M. Hegazi and Abdullah H. Al-Grainees

Summary

The patent relates to a small volume apparatus and a trial-and-error method for identifying and replicating originaltarget liquid blends of unknown ratios by employing laser-induced fluorescence spectroscopy.

STORAGE TANK FLOATING ROOF SUMP WITHEMERGENCY OVERFLOW

Granted Patent: U.S. 8,746,482, Grant Date: June 10, 2014Mohammed Ben Afeef

Summary

The patent relates to a drainage device for use on a float-ing roof of a storage tank for liquid products.

AUXILIARY PRESSURE RELIEF RESERVOIR FORCRASH BARRIER

Granted Patent: U.S. 8,753,034, Grant Date: June 17, 2014Bandar Al-Qahtani

Summary

The patent relates to hydraulically powered vehicle crashbarrier systems, in particular vehicle crash barrier systemshaving an emergency mode of operation to rapidly raisethe crash barrier.

DISPOSAL OF SULFUR THROUGH USE AS SAND-SULFUR MORTAR

Granted Patent: U.S. 8,758,212, Grant Date: June 24, 2014 Mohammed Al-Mehthel, Saleh Al-Idi, Mohammed Maslehuddin,Mohammed R. Ali and Mohammed S. Barry

Summary

The patent relates to a composition and method for dis-posing of sulfur by converting waste sulfur to a usefulproduct, namely, by producing a sulfur-based mortar.

IONIC LIQUID DESULFURIZATION PROCESSINCORPORATED IN A LOW PRESSURE SEPARATOR

Granted Patent: U.S. 8,758,600, Grant Date: June 24, 2014Omer R. Koseoglu and Adnan Al-Hajji

Summary

The patent relates to a system and process for desulfuriz-ing hydrocarbon fractions, and in particular, to a systemand process that integrates ionic liquid extractive desulfur-ization with a hydroprocessing reactor.

SEISMIC IMAGE FILTERING MACHINE TOGENERATE A FILTERED SEISMIC IMAGE,PROGRAM PRODUCTS AND RELATED METHODS

Granted Patent: U.S. 8,762,064, Grant Date: June 24, 2014Saleh Al-Saleh

Summary

The patent relates to the field of geophysical subsurfaceseismic imaging in geophysical seismic exploration. Morespecifically, this invention generally relates to machines,program products and methods to generate filtered seis-mic images based on seismic image data filtered by attenu-ating coherent noise from unfiltered seismic image datausing a plurality of nonstationary convolution operatorsas local filters at each spatial location of an unfiltered seismic image wavefield.


PERFORMANCE GRADED, SULFUR MODIFIEDASPHALT COMPOSITIONS FOR SUPER PAVECOMPLIANT PAVEMENTS

Granted Patent: U.S. 8,772,380, Grant Date: July 8, 2014Milind M. Vaidya, Anwar H. Khawajah, Rashid M. Othman andLaurand Lewandowski

Summary

The patent relates to an asphalt concrete mixture, an as-phalt binder composition and methods of preparing theasphalt concrete mixture.

SAND PRODUCTION CONTROL THROUGH THEUSE OF MAGNETIC FORCES

Granted Patent: U.S. 8,776,883, Grant Date: July 15, 2014Ashraf M. Al-Tahini

Summary

The patent relates to a method for controlling the amountof sand produced from a wellbore. More particularly, theinvention relates to a method of using magnetic forces tocontrol the flow of loose sand particles within an under-ground formation to prevent the loose sand particles fromdamaging downhole tools.

WATER SELF-SHUTOFF TUBULAR

Granted Patent: U.S. 8,789,597, Grant Date: July 29, 2014Mohammad Al-Shammary

Summary

The patent relates to controlling the production of oil andgas reservoirs. More specifically, the invention relates toan apparatus and method for controlling water produc-tion with a multilayered tubular and a water sensitivecomposite.

INTEGRATED DEASPHALTING AND OXIDATIVEREMOVAL OF HETEROATOM HYDROCARBONCOMPOUNDS FROM LIQUID HYDROCARBONFEEDSTOCKS

Granted Patent: U.S. 8,790,508, Grant Date: July 29, 2014Omer R. Koseoglu and Abdennour Bourane

Summary

The patent relates to oxidative desulfurization, and moreparticularly, to a process for integrated deasphalting andoxidative removal of heteroatom-containing hydrocarboncompounds, such as organosulfur compounds, of liquidhydrocarbon feedstocks.

BLOCKED VALVE ISOLATION TOOL

Granted Patent: U.S. 8,800,602, Grant Date: August 12, 2014Mohammad Al-Shammary

Summary

The patent relates to the field of gas treatment and pro-duction facilities, and particularly to the procedures em-ployed in a portion of a gas flow duct system for isolationand removal of a valve for inspection, repair or replacement.

METHOD FOR REAL-TIME MONITORING ANDTRANSMITTING HYDRAULIC FRACTURE SEISMICEVENTS TO SURFACE USING THE PILOT HOLE OFTHE TREATMENT WELL AS THE MONITORINGWELL

Granted Patent: U.S. 8,800,652, Grant Date: August 12, 2014Kirk M. Bartko and Brett W. Bouldin

Summary

The patent relates to the field of hydraulic fracturing,monitoring and data transmission of microseismic infor-mation from a zone of interest within a reservoir. Moreparticularly, it relates to the utilization and employment ofelectrically and physically isolated downhole acousticmonitoring equipment within a fracturing treatment wellto detect microseismic events during fracturing operations.

PARTIALLY RETRIEVABLE SAFETY VALVE

Granted Patent: U.S. 8,800,668, Grant Date: August 12, 2014Brett W. Bouldin and Stephen Smith

Summary

The patent relates to deep-set safety valves used in subter-ranean well production. More specifically, the invention relates to deep-set safety valves used in connection withsubmersible pumps for controlling a well.

SYSTEM FOR MEASUREMENT OF MOLTENSULFUR LEVEL IN RECEPTACLES

Granted Patent: U.S. 8,801,276, Grant Date: August 12, 2014Adel S. Al-Misfer

Summary

The patent relates to the measurement and control of theflow of molten sulfur that is being added to a container orreceptacle, for example, to a steam jacketed tank truck fortransportation or to a sulfur pit for storage.


SOUR GAS AND ACID NATURAL GAS SEPARATIONMEMBRANE PROCESS BY PRE-REMOVAL OFDISSOLVED ELEMENTAL SULFUR FOR PLUGGINGPREVENTION

Granted Patent: U.S. 8,801,832, Grant Date: August 12, 2014Milind M. Vaidya, Jean Pierre Ballaguet, Sebastien A. Duval andAnwar H. Khawajah

Summary

The patent relates to methods for removing sulfur fromgas streams prior to sending the gas streams to gas separa-tion membranes.

CATALYTIC REFORMING PROCESS AND SYSTEMFOR PRODUCING REDUCED BENZENE GASOLINE

Granted Patent: U.S. 8,801,920, Grant Date: August 12, 2014Omer R. Koseoglu and Abdennour Bourane

Summary

The patent relates to the catalytic reforming apparatusand processes, particularly for producing gasoline of reduced benzene content.

SUPER RESOLUTION FORMATION FLUID IMAGINGDATA ACQUISITION AND PROCESSING

Granted Patent: U.S. 8,803,077, Grant Date: August 12, 2014Howard K. Schmidt

Summary

The patent relates to imaging subsurface structures, partic-ularly hydrocarbon reservoirs and fluids therein; moreparticularly, it relates to cross-well and borehole to surfaceelectromagnetic (BSEM) surveying.

MICROWAVE PROMOTED DESULFURIZATION OFCRUDE OIL

Granted Patent: U.S. 8,807,214, Grant Date: August 19, 2014M. Rashid Khan and Emad N. Al-Shafei

Summary

The patent relates to the processing of crude oil using microwave energy to reduce the sulfur content.

PROCESS DEVELOPMENT BY PARALLELOPERATION OF PARAFFIN ISOMERIZATION UNITWITH REFORMER

Granted Patent: U.S. 8,808,534, Grant Date: August 19, 2014Cemal Ercan, Yuguo Wang, Mohammad Al-Dossary and RashidM. Othman

Summary

The patent relates to a process for refining naphtha. Morespecifically, embodiments of the invention utilize two iso-merization units and a reforming unit to create a gasolineblend having an improved octane rating as compared tothe naphtha and/or to produce concentrated reformate forpetrochemicals.

INTEGRATED SYSTEM FOR MONITORINGPERMEATE QUALITY IN WATER TREATMENTFACILITIES

Granted Patent: U.S. 8,808,539, Grant Date: August 19, 2014Nicos Isaias, Ioannis Gragopoulos and Anastasios Karabelas

Summary

The patent relates to a method and apparatus for monitor-ing permeate quality in a water treatment process. Morespecifically, the invention relates to a method and appara-tus for monitoring the performance of individual mem-brane elements in a reverse osmosis or nanofiltrationdesalination of a water treatment plant.

DEEP-READING ELECTROMAGNETIC DATAACQUISITION METHOD

Granted Patent: U.S. 8,812,237, Grant Date: August 19, 2014Alberto F. Marsala, Saleh B. Al-Ruwaili, Shouxiang Ma, MichaelWilt, Steve Crary and Tarek Habashy

Summary

The patent relates to the planning, acquisition, processingand interpretation of geophysical data, and more particu-larly, to methods for interpreting deep-reading electromag-netic data acquired during a field survey of the subsurface.

AUTOMATED METHOD FOR QUALITY CONTROLAND QUALITY ASSURANCE OF SIZED BRIDGINGMATERIAL

Granted Patent: U.S. 8,813,585, Grant Date: August 26, 2014Md. Amanullah, John T. Allen and Mohammed Kilani

Summary

The patent relates to drill-in fluids used in oil and gasdrilling, and in particular, to a laboratory method for eval-uating the durability of sized bridging materials used inthe formulation of drill-in fluids to eliminate or minimizeformation damage.


PROCESS FOR UPGRADING HEAVY AND HIGHLYWAXY CRUDE OIL WITHOUT SUPPLY OFHYDROGEN

Granted Patent: U.S. 8,815,081, Grant Date: August 26, 2014Ki-Hyouk Choi

Summary

The patent relates to a continuous process for upgradingheavy crude oil and highly waxy crude oil to producemore valuable crude oil feedstock having a higher APIgravity; lower content of asphaltene, sulfur, nitrogen andmetallic impurities; increased middle distillate yield;and/or a reduced pour point.

APPARATUS AND METHOD FOR MULTI-COMPONENT WELLBORE ELECTRIC FIELDMEASUREMENTS USING CAPACITIVE SENSORS

Granted Patent: U.S. 8,816,689, Patent Date: August 26, 2014Daniele Colombo, Timothy H. Keho, Michael A. Jervis and BrettW. Bouldin

Summary

The patent relates to an apparatus and method for evalu-ating oil and gas reservoir characteristics. More specifi-cally, the invention relates to triaxial field sensors for lowfrequency electromagnetic fields.

ELECTROCHEMICAL PROMOTION OF CATALYSISIN HYDRODESULFURIZATION PROCESSES

Granted Patent: U.S. 8,821,715, Grant Date: September 2, 2014Ahmad D. Hammad, Esam Z. Hamad and Mohammed S. Elanany

Summary

The patent relates to the removal of sulfur from hydrocar-bon streams, and more particularly, to a catalytic hydro-desulfurization process, which allows for the in situ con-trol of catalyst activity and selectivity.

PROCESS FOR UPGRADING HYDROCARBONFEEDSTOCKS USING SOLID ADSORBENT ANDMEMBRANE SEPARATION OF TREATED PRODUCTSTREAM

Granted Patent: U.S. 8,821,717, Grant Date: September 2, 2014Omer R. Koseoglu

Summary

The patent relates to the upgrading of hydrocarbon oilfeedstock to remove undesirable sulfur and nitrogen containing compounds using solid adsorbents.

CIRCULATION AND ROTATION TOOL

Granted Patent: U.S. 8,826,992, Grant Date: September 9, 2014Shaohua Zhou

Summary

The patent relates to making up and breaking out pipeconnections during drilling operations. In particular, it re-lates to a tool for allowing circulation of fluid through,and rotation of, a pipe string while making up or breakingout pipe connections.

HYDROCRACKING PROCESS WITH FEED/BOTTOMS TREATMENT

Granted Patent: U.S. 8,828,219, Grant Date: September 9, 2014Omer R. Koseoglu

Summary

The patent relates to hydrocracking processes, and in par-ticular, to hydrocracking processes adapted to receive mul-tiple feedstreams.

SELF-CONTROLLED INFLOW CONTROL DEVICE

Granted Patent: U.S. 8,833,466, Grant Date: September 16, 2014Shaohua Zhou

Summary

The patent relates to well production devices, and in par-ticular, to a self-controlled inflow control device.

DRILLING, DRILL-IN AND COMPLETION FLUIDSCONTAINING NANOPARTICLES FOR USE IN OILAND GAS FIELD APPLICATIONS AND METHODSRELATED THERETO

Granted Patent: U.S. 8,835,363, Grant Date: September 16, 2014Md. Amanullah and Ziad Al-Abdullatif

Summary

The patent relates to drilling, drill-in and completion flu-ids and related additives for use in oil and gas field appli-cations. More specifically, the invention relates to drilling,drill-in and completion fluids that include nanoparticlesand related additives.

VALVE ACTUATOR FAULT ANALYSIS SYSTEM

Granted Patent: U.S. 8,838,413, Grant Date: September 16, 2014Pablo D. Genta

Summary

The patent relates to valve actuators, and more specifi-cally, to a fault analysis system for detecting and locating


actuator malfunctions, performance deviations and failures,as well as causal factors of any such malfunction, per-formance deviation or failure, to facilitate the determina-tion of adequate remedial actions.

INTEGRATED HYDROTREATING ANDISOMERIZATION PROCESS WITH AROMATICSEPARATION

Granted Patent: U.S. 8,852,426, Grant Date: October 7, 2014Omer R. Koseoglu

Summary

The patent relates to hydrotreating processes to efficientlyreduce the sulfur content of hydrocarbons.

DEVICE AND METHOD FOR MEASURINGELEMENTAL SULFUR IN GAS IN GAS LINES

Granted Patent: U.S. 8,852,535, Grant Date: October 7, 2014Ihsan Al-Taie, Abdulaziz Al-Mathami and Helal Al-Mutairi

Summary

The patent relates to the sampling of gases, and more par-ticularly, to a device and method for measuring the levelof elemental sulfur present in a gas in a gas line.

STRUCTURE INDEPENDENT ANALYSIS OF 3DSEISMIC RANDOM NOISE

Granted Patent: U.S. 8,855,440, Grant Date: October 7, 2014Saleh Al-Dossary and Yuchun Wang

Summary

The patent relates to the field of image processing andspecifically to the suppression of image data to estimateand identify random noise in post-stacked three-dimen-sional seismic data containing geological structures, suchas faults.



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GUIDELINES FOR SUBMITTING AN ARTICLE TO THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY

These guidelines are designed to simplify and help standardizesubmissions. They need not be followed rigorously. If youhave additional questions, please feel free to contact us atPublic Relations. Our address and phone numbers are listedon page 85.

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EditorThe Saudi Aramco Journal of TechnologyC-86, Wing D, Building 9156Dhahran 31311, Saudi ArabiaTel: +966-013-876-0498E-mail: [email protected]

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Summer 2015 March 1, 2015 June 30, 2015Fall 2015 June 1, 2015 September 30, 2015Winter 2015 September 1, 2015 December 31, 2015Spring 2016 December 1, 2015 March 31, 2016

First Successful Proppant Fracture for Unconventional Carbonate Source Rock in Saudi ArabiaNayef I. Al Mulhim, Ali H. Al-Saihati, Ahmed M. Al-Hakami, Moataz M. Al-Harbi and Khalid S. Al-Asiri

ABSTRACT

Widely recognized as the world leader in crude oil production, Saudi Aramco has only recently begun to explore forunconventional gas resources. Saudi Aramco started evaluating its unconventional reservoirs to meet the anticipated futuredemands for natural gas. One of the subject plays that is currently being evaluated is a carbonate source rock with nanoDarcypermeability and very low porosity. The target formation has few, if any, analogs that can be used for comparison. Knowledgeof the formation characteristics, geomechanics, stimulation response and production potential has been nonexistent untilrecently.

Well Site Energy Harvesting from High-Pressure Gas ProductionDr. Jinjiang X. Xiao, Wessam A. Busfar, Rafael A. Lastra and Muhammad Adnan

ABSTRACT

Chokes are control valves built into the production systems so that wells can be produced at desired rates, while at the sametime reservoir depletion and sweep can be optimized, and formation and well completion integrity can be protected. The use ofsurface chokes also allows surface flow lines and facilities to be designed more economically due to reduced pressure ratings.Substantial pressure drops can occur through well surface chokes, especially at early stages of production when the reservoirpressure is still high and lower choke settings are applied. This article investigates energy loss through wellhead chokes for gaswells, with attention to the laws of thermodynamics.

Optimization and Post-Job Analysis of the First Successful Oil Field Multistage Acid Fracture Treatment in Saudi ArabiaTariq A. Al-Mubarak, Majid M. Rafie, Dr. Mohammed A. Bataweel, Rifat Said, Hussain A. Al-Ibrahim, Mohammad F. Al-Hajri, Peter I. Osode,

Abdullah A. Al-Rustum and Omar Al-Dajani

ABSTRACT

Multistage acid fracture treatments are utilized in low permeability carbonate reservoirs (permeability <10 millidarcies (mD)) tostimulate the formation by creating highly conductive fractures in the formation and bypassing near wellbore damage. Thefracture is generated at high pressures, which are required to break the rock open, while using a viscous pad. The fracture isthen kept open by adding gelled or emulsified acid to create uneven etches on the surface of the fracture.

Microgravity Flood Front Monitoring: Reducing Inversion Ambiguity by Use of Simulation A Priori Data Stig Lyngra, Dr. Gleb Dyatlov, Dr. Alberto F. Marsala, Antonius M. (Ton) Loermans, Dr. Yuliy A. Dashevsky, Alexandr N. Vasilevskiy,

Dr. Carl M. Edwards and Dr. Daniel T. Georgi

ABSTRACT

Traditional areas using gravimetry methods are surface gravity for mining and oil exploration and bulk density borehole gravitylogging. Large-scale reservoir saturation monitoring is a new application. Substitution of oil or gas by water leads to densitychanges in large reservoir volumes, which causes time-dependent gravity field changes.

This article presents a time-lapse gravity data inversion problem for a complex reservoir. The customary bitmap approachrequires many input parameters and results in a well-known inversion ambiguity. The same ambiguity in this work was reducedby introducing a priori information obtained by biasing the inversion with history matched reservoir simulation data.

Additional Content Available Online at: www.saudiaramco.com/jot.com

creo

On the Cover

Multiple FIB-SEM images were used to construct a 3D charac-

terization for different rock properties in a short turnaround time.

Representative 3D FIB-SEM images were used to quantify mineralogy,

organic matter and porosity. The 3D volume shows organic matter in

green, connected porosity in blue and disconnected porosity in red.

The Saudi Aramco Journal of Technology ispublished quarterly by the Saudi Arabian OilCompany, Dhahran, Saudi Arabia, to providethe company’s scientific and engineeringcommunities a forum for the exchange ofideas through the presentation of technicalinformation aimed at advancing knowledgein the hydrocarbon industry.

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EDITORIAL ADVISORS

Zuhair A. Al-HussainVice President, Southern Area Oil Operations

Ibraheem AssaadanExecutive Director, Exploration

Abdullah M. Al-GhamdiGeneral Manager, Northern Area Gas Operations

Salahaddin H. DardeerManager, Jiddah Refinery

EDITORIAL ADVISORS (CONTINUED)

Sami A. Al-KhursaniProgram Director, Technology

Ammar A. NahwiManager, Research and Development Center

Waleed A. MulhimManager, EXPEC ARC

CONTRIBUTIONS

Relevant articles are welcome. Submissionguidelines are printed on the last page.Please address all manuscript and editorial correspondence to:

EDITOR

William E. BradshawThe Saudi Aramco Journal of TechnologyC-86, Wing D, Building 9156Dhahran 31311, Saudi ArabiaTel: +966-013-876-0498E-mail: [email protected]

Unsolicited articles will be returned onlywhen accompanied by a self-addressedenvelope.

Khalid A. Al-FalihPresident & CEO, Saudi Aramco

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ISSN 1319-2388.

© COPYRIGHT 2014 ARAMCO SERVICES COMPANYALL R IGHTS RESERVED

No articles, including art and illustrations, inthe Saudi Aramco Journal of Technology,except those from copyrighted sources, maybe reproduced or printed without thewritten permission of Saudi Aramco. Pleasesubmit requests for permission to reproduceitems to the editor.

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Additional articles that were submitted for publication in the Saudi Aramco Journalof Technology are being made available online. You can read them at this link onthe Saudi Aramco Internet Website: www.saudiaramco.com/jot

Organic matter and porosity for shale gas samples werecharacterized by multi-scale imaging technology. Highresolution FIB-SEM images were utilized to link betweenmineralogy, porosity and flow properties.

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