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Enhancing carbonatE rEsErvoir charactErization

DEfInIng A fIElD stRAtEgyOne of the key challenges in any oil and gas reservoir is to establish how hydrocarbon fluids will move through the structure during production. Once the engineers have established the routes that fluids will take through the rock and identified where hydrocarbons might be left behind, they can develop strategies to maintain production levels and boost total recovery.

In carbonate reservoirs, the assessment of flow paths is complicated by features such as natural fractures, uncertainty over the connectivity between the various parts of the reservoir, and variations in wettability that will influence the effectiveness of recovery methods such as water injection.

In this article, Bernard Montaron, Michael stundner, and georg Zangl examine methods that characterize fracture pathways, establish the degree of fluid exchange between reservoir compartments, and enable petrophysicists to define wettability variations across the field.

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Reservoir characterization is the act of building a model of a reservoir based on its characteristics with respect to fluid flow. to achieve an accurate picture of a reservoir and how it will behave during its productive life, reservoir engineers must be able to identify the main flow pathways and define the connections between the various parts of the reservoir. Once the engineers have established the routes that the fluids take through the rock and identified where hydrocarbons might be left behind, they can develop strategies to maintain production levels and boost total recovery.

fRActuREs, cOnnEctIvIty, AnD wEttABIlItythe natural fracture networks found in carbonate rocks often have a controlling influence on fluid movement. fractures can be responsible for water breakthrough, gas coning, and drilling problems such as mud losses and stuck pipe (fig. 4.1). Most carbonate reservoirs contain fractures that can range from isolated microscopic fissures to kilometer-long structures containing many individual fractures.

In oil and gas reservoirs, the natural fractures may serve as conduits that enable or enhance the flow of hydrocarbons, or they may act as barriers preventing or slowing the movement of liquids and gases and dividing the reservoir into compartments with different pressure regimes and oil/water contacts (Owc). In some fields, a set of fractures may perform both roles at different times or at different pressures.

where fractures split the reservoir into distinct hydrocarbon volumes, geologists and engineers need to establish the volume and the extent of each compartment using a range of geochemical and production tests. Identifying the individual reservoir compartments and the degree of fluid connectivity between them is a key aspect of reservoir engineering in carbonate reservoirs. this becomes particularly important during the later stages of production when bypassed compartments may contain large and untapped hydrocarbon volumes (fig. 4.2).

wettability has always been recognized as an important parameter to be considered in oil reservoirs. However, accounting for the distribution of wettability in carbonate reservoirs is a concept that has emerged only recently in the industry. wettability has a strong influence on reservoir performance and on the proportion of oil that can be recovered. failure to characterize the wettability regime can lead engineers to implement development plans that can damage the reservoir. new logging techniques combining measurements from multiple lwD and wireline tools can now be used to help characterize wettability in open hole. Key measurements include nMR, resistivity, and any other measurement sensitive to saturation, including dielectric, sigma neutron capture cross section and carbon/oxygen.

0.0 0.1 0.2 0.3

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4.1: Fracture corridors can control the movement of injected water and sweep efficiency. A central injector well is sweeping oil to four producers located in the corners of a homogeneous reservoir block (A) and a reservoir with large fracture corridors (B). Recovery is reduced in the fractured reservoir.

4.2: A detailed understanding of the interactions between reservoir compartments will guide field development planning and may help to locate bypassed hydrocarbon zones.

Figure 4.1

Figure 4.2

Carbonate experts are developing ways to apply both old and new technology to better effect in reservoir characterization. R&D programs conducted by Schlumberger have helped the industry to enhance the characterization of fractured reservoirs, to establish the connectivity between the compartments of complex reservoirs, and to determine how wettability variations influence recovery factors.

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JointMode 1 (opening)

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FaultMode 2 (sliding)

Fracture types

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4.3: The main development mechanisms for natural fractures.

Figure 4.3

unDERstAnDIng tHE fRActuRE nEtwORKfaults and fractures develop through a range of geological mechanisms (fig. 4.3). faced with this complexity, engineers must work to identify fracture types, origins, scales, and connectivity, and the physical controls on their behavior.

fractures do not always present high-permeability pathways for fluids. In many fields, some or all of the fractures may be cemented, which effectively compartmentalizes the reservoir and makes production more difficult. Only when earth scientists and engineers achieve a thorough understanding of the fault and fracture networks, can they decide whether the fractures in the reservoir will help or hinder hydrocarbon production and then select the most effective plan for field development.

the oil and gas industry has understood the potential importance of fractures for decades. However, clear understanding of the range and diversity of fracture structures and the roles they play in determining reservoir storage capacity and productivity has only been achieved in recent years. the total porosity contribution from fractures is typically 0.1% or less, even in heavily fractured reservoirs. In reservoirs composed of porous rocks, that is all reservoirs other than fractured basement, the fracture porosity is a very small fraction of total porosity. Most of the hydrocarbon reserves are in the matrix, but the hydrocarbons in the fractures are much more mobile and easy to produce.

fractured reservoirs often deliver high initial flow rates from discovery and early development wells. this may lead engineers to overestimate a reservoir’s potential production because producible hydrocarbons can quickly be depleted once the oil contained in the fracture network has been produced. fractured reservoirs often appear to have thick reservoir zones, but the Owc can be hard to define and, when this is the case, engineers may have difficulty in accurately estimating reserves. Indeed, within the same zone of a producing reservoir, the Owc in the fractures may be very different to the Owc in the matrix. this difference is due to the large permeability contrast between the two reservoir elements.

fRActuRE DIstRIButIOns AnD REsERvOIR flOw In carbonate reservoirs, the volume of oil and the rate at which it can be produced are usually influenced by a fracture network that extends throughout the field. However, the analytical tools developed to examine fractures in clastic reservoirs can only measure fracture properties in the reservoir close to the well. this leaves the geoscientists attempting to predict the reservoir-wide distribution of fractures using indirect observations or assumptions. In naturally fractured carbonate reservoirs, these methods provide insufficient data to define the reservoir framework.

Recognizing the need for a more detailed picture of fracture distributions and reservoir flow structure, schlumberger has a broad, cross-discipline commitment to continuously improving fracture modeling in carbonates.

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JaCqueS PionJacques Pion is currently geosciences manager at the Total representative office in Abu Dhabi. He has held various positions with Total worldwide, including head of geophysical R&D until 1996, geosciences manager on several Iranian buy-back contracts until 2001, and geosciences manager for Total Angola until 2004.

q: What is specific/unique about characterizing geological structures in carbonates?carbonate rocks present a special challenge in terms of rock physics: the Poisson’s ratio in carbonates is 0.28 for calcite, 0.2 for dolomite (compared with 0.1 for clastic rocks) and this makes reservoir characterization much more difficult at least through a classical acoustic inversion. when hydrocarbon is present in a carbonate unit it often preserves the rock’s petrophysical properties; but where the rock matrix is exposed to water, diagenetic effects will create different rock properties. fluid substitution algorithms need to take diagenesis into account.

In clastic rocks, lateral seal considerations are very important and fault structures are usually assessed to determine connectivity between adjacent reservoirs. In contrast, vertical communication is dominant in carbonate rocks and stacked carbonate reservoirs are often found to communicate through vertical “channels” created by porous facies and/or fractures. faults also play an important role defining fluid flow in carbonates, but subtle faults with very small throws are often ignored even though they may have calcite cementation that creates an effective barrier.

q: How are you addressing these challenges in Total?we’ve been pioneers in AvO-AZ (azimuthal variation of the AvO response) since the early 1990s. for example, in 1991 we published a study about positive AvO-AZ effects in a carbonate reservoir in the Paris basin. However, we recognize that AvO methods, and AvO-AZ in particular, are very difficult to apply in carbonates. therefore, our emphasis is on using the interpretation software sIsMAgE for subtle fault tracking with a combination of attributes and the superposition on vertical sections of what is tracked on slices.

In total we investigate the rock physics model and the present-day stress field as these are key for characterizing particular directions for sealing or nonsealing effects. we also have a

precise calibration for seismic near the wells: we can check for subtle faults using cores interpretation, image logs, wireline logs, pressure data, and well test interpretation. we take this approach because structural attributes drive the distribution of fracture properties in the model.

q: What are the most common challenges you see in the Middle east region with regards to carbonates?there are two main challenges. the first is to define the scale of heterogeneities that is meaningful for reservoir development and the second is to establish which faults are sealing and which nonsealing. An additional challenge is to find and study relevant geological analogs, and we are very fortunate to have in the south of france well-studied rock outcrops that provide a valid analog to the carbonate reservoirs in the Middle East.

q: How important is accurate structural geology in defining a field development plan for carbonate reservoirs?Accurate structural geology is essential for the long-term life of the reservoir. A clear understanding of heterogeneities helps with decisions on water management and on the type of injection required; and guides our plans for tertiary recovery. with low permeability carbonate oil reservoirs we have to deal with a paradox: the tighter the rocks are, the more prone to fracturing they will be, and that creates a major challenge!

today we’re working with the Abu Dhabi operating companies ADcO and ADMA in order to develop more complex and thinner carbonate reservoirs for which improved oil recovery methods (such as artificial lift, complex wells) will be required to start much sooner. total has a special role to play in this because the Abu Al Bukhoosh field operated by total in Abu Dhabi is much more mature than the operating companies’ larger fields and has already been the subject of numerous experimental improved oil recovery (IOR) techniques designed to push the recovery factor beyond initial expectations. On the Abu Al Bukhoosh field, structural geology studies have proved very important for guiding IOR actions, and the experience gained on this field can be considered as a pilot for further improved recovery projects.

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4.4: High-permeability fracture corridors consist of numerous fractures that share the same orientation and are contained in a relatively small volume within the reservoir.

4.5: In this Abu Dhabi well, all the produced water (160 m3/d) came from a single, 9-m wide fracture corridor.

Figure 4.4

Figure 4.5

Fracture corridorsDiffuse fractures are spread through the reservoir, and their density and orientation can be measured with high-definition seismic surveys that uniformly sample the offset–azimuth continuum. However, some carbonate reservoirs contain large-scale heterogeneities known as fracture corridors. these structures consist of numerous fractures that share the same orientation and are contained in a relatively small volume within the reservoir, typically a few meters wide, a few tens of meters high, and several hundred meters long (fig. 4.4). A major fracture corridor might contain 100,000 individual fractures and provide a permeability of more than 50 D.

the high permeabilities found in fracture corridors mean that they provide direct conduits for injected or produced water. this can result in high water cuts, early water breakthrough, and reduced total oil recovery (fig. 4.5). However, fracture corridors also provide opportunities. If the reservoir engineer has information about the presence and positions of fracture corridors before production begins, it should be possible to incorporate them into the field development plan and to drill injectors and producers that complement the reservoir’s natural flow patterns and so stimulate hydrocarbon production.

fracture corridors can control production and recovery. field development plans are often devised and implemented without prior knowledge of the fracture corridors in the reservoir (fig. 4.6A). Early water breakthrough might result in many wells being watered out within a few years of production (fig. 4.6B), while half the total oil production for the field comes from a few wells, in this example only three wells are producing oil (fig. 4.6c). faced with this kind of situation, the only way that field operators can be sure that they will improve field and well performance is by characterizing the fracture network so that any remediation programs and additional wells can achieve their goals.

when reservoir engineers know the locations of fracture corridors before they develop a field, they can optimize production by placing shorter horizontal injection wells and production wells in the best locations (figs. 4.6D and 4.6E). the latest seismic technology and advanced processing methods enable the presence and location of fracture corridors within reservoirs to be determined. this information is vital for effective well placement and reservoir simulations.

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MAPPIng fRActuREsBorehole imaging can be used to locate and describe fractures that intersect a well, but characterizing the wider fracture network requires a different approach. seismic surveys, with their broad areal coverage and ongoing improvements in image resolution, are ideal for detailed definition of reservoir-scale heterogeneities.

Data from Q-technology* single-sensor seismic hardware and software combined with new seismic processing methods enables earth scientists to detect and evaluate fracture properties between wells. the analysis of azimuthal anisotropy parameters (the variations in the velocity and amplitude of seismic waves traveling in different directions) can reveal the intensity and orientation of subseismic fractures between wells.

seismic attribute processing reveals subtle structural details in the reservoir, and interpreters can use curvature attributes to infer stress regimes that correspond to fracture density.

Locating fracture corridorsthe fcM* fracture cluster mapping workflow, developed by geoscientists in the Data & consulting services (Dcs) with the support of the schlumberger stavanger Research (ssR) team in norway, combines high-resolution seismic data with log data and uses the automated structural interpretation capabilities in the Petrel* seismic-to-simulation software to locate fracture corridors within the reservoir.

borehole imaging can be used to locate and describe fractures that intersect a well, but characterizing the wider fracture network requires a different approach. seismic surveys, with their broad areal coverage and ongoing improvements in image resolution, are ideal for detailed definition of reservoir-scale heterogeneities.

4.6: A typical field development plan might involve vertical producers and horizontal injector wells around the edge of the field (A). After 5 years, 10 of the wells might have watered out (B and C) and half of the oil production could be coming from just three wells. Through knowing the location of fracture corridors (D), the development team could have optimized the field by drilling shorter horizontal injectors and positioning them away from the fracture corridors. Deviated producers could have been used to intersect the fracture corridors and to drain compartments (E).

Figure 4.6

Water Oil Gas

A B C D E

Fracture cluster mapping in Kuwaitthe fcM workflow, which schlumberger launched in 2007, is based on the assumption that when natural fractures form large clusters (with extents of 10–30 m or more) they should be visible in 3D seismic data. the fcM workflow integrates borehole data with the 3D seismic data to optimize the extraction process achieved through discontinuity extraction software (DEs) processing.

seismic attributes that are sensitive to fracture clusters are identified and input to the DEs. the 3D seismic data must have optimal spatial/temporal bandwidth and signal-to-noise ratio to ensure that the attributes input to the DEs processing contain meaningful information for fracture cluster mapping. this may require special acquisition design and data processing workflows using single-sensor data. the designs of the directional (azimuthal) and inclination (dip) filters used in the DEs processing are based on the analysis of cores, borehole images, sonic logs, vsP surveys and other information on the geology or geomechanics of the field.

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Time sliced from a 3D cube showing fracture clusters output by DES using azimuth filter opened to 030–090 and 210–270

Time sliced from a 3D cube showing fracture clusters output by DES using azimuth filter opened to 090–150 and 270–330

Time sliced from 3D cube obtained by merging the 3D volumes of fracture clusters output by three runs of DES using three different rangesof azimuth filters

4.7: FCM workflow and ant tracking.

4.8A: North-northeast–south-southwest trending fracture clusters at a horizon within the Middle Marrat carbonate reservoir, extracted from the seismic volume using the DES.

Figure 4.7

Figure 4.8aFine-tuning for cluster detectionthe structural and tectonic history of the study area is also used to optimize parameters and assess results. the general DEs processing often overlooks some fracture clusters when the directional filter is kept open to all 360˚ of azimuth with a fixed range of features inclination. In this situation, the DEs processing tends to follow the strongest lateral discontinuities in the vertical plane, those caused by larger fracture clusters, and to miss the weaker signatures of smaller fracture clusters. to capture such discontinuities, the directional filter can be divided into windows or ranges and the inclination filter can be set at several dip inclination ranges.

DEs processing is run separately for each set of directional and inclination filters. Each run of DEs provides a 3D volume cube of fracture cluster lineaments. these cubes are then merged into a single 3D volume cube that gives a much more realistic picture of the fracture clusters that are present (fig. 4.7).

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FCM in Kuwaitthe fcM workflow was applied to the sequence of Jurassic carbonates in five fields (northwest Raudhatain, Raudhatain, umm niqqa, sabriyah, and Bahra) in the northern part of Kuwait. the sabriyah field was selected as the key area for the study because four wells were being drilled there at the time and it offered a challenging structural setting (a pop-up structure caused by transpression along the east and west bounding strike–slip faults).

fracture evidence at the existing wells and data from the newly drilled wells were used to validate the fracture clusters located using the DEs on the seismic volume. figure 4.8A shows mainly north-northeast–south-southwest trending fracture clusters at a horizon within the Middle Marrat carbonate reservoir extracted from the seismic volume using the DEs. fracture clusters of exactly the same orientation and inclination were observed in the 3D cube throughout the Marrat section.

However, borehole data from one of the existing wells showed a dominance of east-northeast–west-southwest striking fractures (more than 400 open fractures) within Marrat. when the DEs process was applied to the same seismic attribute volume, but with two different azimuthal filters (315–045 and 135–225; and 045–135 and 225–315), fracture clusters with north-northeast–south-southwest, east-northeast–west-southwest, northeast–southwest, northwest–southeast, and west-northwest–east-southeast strikes were highlighted (fig. 4.8B). the north-northeast–south-southwest striking fracture clusters are probably fold-related, as they are parallel to the axis of the sabriyah anticline, and the east-northeast–west-southwest and west-northwest–east-southeast striking fracture clusters, which are more concentrated within the sabriyah anticline, are possibly Riedel shears. the results were validated at the locations of existing wells and at the new wells.

4.8B: The FCM workflow enables operators to create 3D maps for all the major fracture corridors in a carbonate field.

Figure 4.8B

Largely north-northeast–south-southweststriking fracture clustersdetected by ant tracking when theazimuth filter wasopened to 315–045and 225–135

Fold-related longitudinal fracture clusters following the north-northeast–south-southwest trending fold axis of Sabriyah anticline

Riedel shears caused by north-northeast–south-southwest striking right-lateral. Strike–slip faults bounding the Sabriyah anticline

Fold-related longitudinal fracture clustersfollowing the fold axis of Sabriyah anticline

Filters: Search azimuth:315–045 and 135–225Dip angle: >70°

Northeast–southwest; east-northeast–west-southwest;northwest–southeast; and west-northwest–east-southeast striking fracture clusters detected when the azimuth filter was opened to 315–045 and 225–135

Filters: Search azimuth:045–135 and 225–315Dip angle: >70°

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4.9: Reservoir engineers can establish the controls on reservoir- and well-scale noncontinuous flow behavior using the DFN workflow and then model the fracture networks and perform dual-porosity and dual-permeability simulations using ECLIPSE* reservoir simulation software.

Figure 4.9the fcM workflow enables operators to create 3D maps for all the major fracture corridors in a carbonate field, as demonstrated by its successful application at five fields in Kuwait. Experience shows that the best results were obtained when using high-resolution seismic technology.

the presence of fracture corridors has often been proposed as an explanation for early water breakthrough. with 3D maps of fracture corridors becoming available, these important structural features can now be integrated into reservoir models to determine optimum well locations by using more realistic simulations. this methodology will help operators to avoid water breakthrough surprises and assist their efforts to increase hydrocarbon recovery factors in carbonate reservoirs and other naturally fractured formations.

A unIfIED MODEl Of tHE fRActuRE nEtwORKIn the past, carbonate reservoirs were developed with little or no information about the fracture network between wells. today, however, reservoir engineers can examine an entire reservoir to obtain a clear understanding of the fracture corridor network, its impact on fluid flow, and how the dynamic stress regime (the geostress) within the reservoir affects permeability. this is achieved using an integrated approach that combines advanced seismic processing and discrete fracture network (Dfn) modeling.

exploiting fracture connectivityAdvanced seismic processing can reveal fracture distribution, but does not provide information about the geomechanical and hydraulic properties of a fracture network. these are the properties that define the dynamic behavior of the fracture network and influence reservoir performance.

Reservoir engineers can create a realistic model for the dynamic behavior of fractures and establish the controls on reservoir- and well-scale discontinuous flow behavior using the Dfn workflow (fig. 4.9). within the workflow, each fracture is described by its physical properties, such as surface area and shape, and each has defined fluid flow properties for permeability, compressibility, and aperture.

“reservoir engineers can create a realistic model for the dynamic behavior of fractures and establish the controls on reservoir- andwell-scale discontinuous flow behavior using the DFn workflow.”

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using Petrel seismic-to-simulation software, engineers can integrate information from numerous sources, including 2D and 3D seismic surveys, maps, outcrops, reservoir geomechanical studies, well logs and tests, flow logs, and structural or depositional conceptual models, to create a unified representation of the reservoir.

A Dfn model typically combines deterministic and stochastic discrete fractures. the deterministic fractures are those seen on fMI* fullbore formation microimager borehole image logs and the fracture corridors that are directly imaged through high-resolution seismic acquisition using Q-technology services. Other, usually smaller-scale, fractures that form diffuse fracture networks are generated stochastically to match their collective properties (density and orientation), as observed in the seismic data. the reservoir model combines the Dfn workflow and the fracture corridors that are directly imaged through seismic imaging using ant tracking.

A typical Dfn model may contain several million fractures, and this information is fed into the EclIPsE reservoir simulation software through an upscaling process. Engineers then generate a 3D simulation grid that contains the fracture porosity, the permeability, and the sigma factor required for a dual-porosity or dual-permeability simulation (fig. 4.10). this model can then be run in the EclIPsE software to provide an accurate picture of fluid flow in the reservoir and enable the engineers to compare the effectiveness of various production strategies.

the combination of the fcM workflow and Dfn modeling in the hands of experienced geoscientists provides the most effective method for modeling fractured reservoirs and optimizing the vital production decisions that are taken at the start of the field development process.

EstABlIsHIng REsERvOIR cOnnEctIvItyA reservoir compartment is a productive segment of an oil or gas field that is not in direct fluid communication with the remainder of the field. Productive compartments may be isolated at the time of sediment accumulation by depositional processes or may become isolated after deposition and burial as a result of diagenesis or structural changes in the rock sequence. Reservoirs that have become compartmentalized require different approaches to interpretation and production than continuous reservoirs, and engineers must be aware that the degree of compartmentalization may change as a result of hydrocarbon production.

compartmentalized fields may be complex, with different Owcs or gas/water contacts in each compartment. As the reservoir is depleted, some of the fractures between the compartments may stop acting as complete lateral seals and enable some communication, which further complicates fluid distribution and movement.

4.10: The key to accurate characterization of fractured reservoirs involves integrating measurements from different disciplines; building accurate geological models that incorporate fractures; and performing simulations using dual-porosity, dual-permeability simulators that correctly predict production history.

Figure 4.10

Combination of input sources Well testsInterference tests

Petrel software ECLIPSE software

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4.12: The extent of the interference between nine different reservoir compartments.

Figure 4.12

Reservoir 1

Reservoir 5 Reservoir 6Reservoir 9

Reservoir 2 Reservoir 7

Reservoir 4 Reservoir 8

Reservoir 3

Thickness of connection indicates interference strength

Res. 2Res. 1

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4.11: A pressure match using several years of production data enables engineers to establish the extent of interference between various reservoir compartments. In this example, the data indicates that there is an exchange of fluids between two compartments.

Figure 4.11

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Measuring and predicting the affects of reservoir connectivityEffective reservoir decisions require access to historical and real-time production data. Reservoir and production engineers can use the DEcIDE!* data mining based production optimization software to generate readily usable information from large volumes of field data. the system’s analytical data mining capabilities make it possible to diagnose reservoir conditions and to conduct predictive modeling. this can guide reservoir management decisions, reveal production opportunities, and prioritize operational decisions, including tasks such as optimizing the field injection/production ratio (IPR), enhancing artificial lift performance, and smart well control.

using the material balance with interference (MBI) method within the DEcIDE! software, engineers can analyze production data to establish the degree of connectivity between reservoir compartments. A large carbonate reservoir may contain dozens of compartments with varying degrees of connectivity.

Engineers can pressure match the various reservoir compartments over a period of production (fig. 4.11) and create an interference matrix (fig. 4.12) that defines the connectivity. the MBI approach is more effective than simple material balance models, is easier to apply than numerical simulation models, and enables production teams to manage their reservoirs interactively.

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applying MBi in the Middle eastIn a major Middle East field, the MBI method was used to investigate production sustainability; to assess whether there had been overinjection of water; to predict future water production for establishing the necessary water handling capacity; and to ascertain the most effective injection allocation to optimize field performance.

the MBI approach was also used to optimize the IPR, to evaluate new workflows for injection management, and to select a new injection scheme that would maintain production.

using the MBI method and artificial intelligence tools (neural network proxy models), schlumberger worked with the field operator to identify the oil and water interference between the reservoir segments and to optimize the injection profile according to the production needs.

the project had three phases: data preparation and analysis; modeling; and forecasting and optimization. the MBI model integrated a range of data types, including produced volumes of oil, water, and gas; injected water volumes; wellhead pressures; test data for oil, water, and gross production rates; water cut; gOR; and Pvt.

Based on the matched MBI model, the team established the optimum injection profile for three different production scenarios and plotted the performance for each option to 2030. the project optimized the IPR from 1.18 to 1.06; refined the segmentation model for the main parts of the field; and identified the oil and water fluxes between the peripheral segments and the central area of the reservoir.

wEttABIlIty, PRODuctIvIty, AnD OIl REcOvERyIn many oilfield applications, rocks are described as being either water-wet or oil-wet. this is an extreme simplification that masks the complexity of wetting physics in reservoir rocks. In a homogeneous, porous material saturated with oil and water, there are many degrees of wetting between strongly water-wet and strongly oil-wet. solids that do not display a marked preference for one fluid over the other are intermediate- or neutral-wet.

Detailed characterizations of formation wettability are crucial for production teams seeking to optimize oil recovery. the wetting preference of reservoir rocks influences many aspects of field performance, particularly when operating companies apply waterflooding or enhanced oil recovery techniques. treating a reservoir as though it were water-wet when it is oil-wet or has mixed wettability may cause irreversible damage.

During primary recovery, wettability influences productivity and oil recovery. the original wettability of a formation and the altered wettability during and after hydrocarbon migration influence the profile of the initial water saturation, Swi, and the production characteristics of the formation.

wettability affects the amount of oil that can be produced at the pore level, as measured after waterflooding by the residual oil saturation, Sor. In a water-wet formation, for example, oil can be in the larger pores disconnected from the continuous body of oil and therefore remain trapped. In an oil- or mixed-wet formation, oil adheres to the rock, thereby increasing the probability of a continuous path to a producing well and resulting in a lower Sor.

Measuring wettabilitywettability can change during and as a result of oil production. for example, asphaltene precipitation in depleting carbonate reservoirs may change their wettability. to appreciate the pore-level changes that control oil production, engineers must understand past and present wettability distributions.

Reservoir wettability is one of many parameters that can be derived from analysis of carbonate core samples (fig. 4.13). However, core wettability can be modified in several ways before the sample reaches the laboratory. Even when efforts are made to preserve the core sample’s original wetting state, drilling mud from the well may contaminate it. As the core is brought to surface, temperature and pressure changes may change the composition of the fluids it contains, sometimes causing asphaltenes and waxes to precipitate and cover the pore surfaces. Once the core has reached the surface, exposure to oxygen may alter the chemical composition of the crude oil it contains and generate surfactants that affect its properties.

the challenges of preserving core samples in pristine condition have led to a method for restoring the original reservoir condition of the core. the first step to restoring cores is a cleaning process that makes the sample water-wet. the core is then saturated in simulated formation brine and aged. finally, it is flooded with crude oil and aged for several weeks at reservoir temperature and pressure. the aim of this procedure is to recreate the wetting state of the formation rock. However, variations in brine or oil composition between the formation and the laboratory can affect the resultant wetting state.

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5-in whole core

1-in core plug

Thin section

Special core analysesRelative permeabilityCapillary pressureWhole core porosity, permeabilitySaturationsCT scanRestored state

Geomechanical analysesCompressive propertiesElastic moduliAcoustic propertiesElectrical propertiesFracture/stress field analyses

Thin-section petrographyPorosity typesMicro fauna, floraDiagenesisCathodoluminescenceGrain size, sorting, etc.Cement analyses

5-in whole core

Core plugsPorosity, permeabilityGrain densityFluid saturationsMercury injection for pore size, capillary pressure

Slabbed core descriptionTextureFauna, floraSedimentologySequence stratigraphyStructures (fractures, etc.)Mini permeameter measurementsBiostratigraphic dating

MineralogyX-ray diffraction, fluorescenceScanning electron microscopy analysesMicroprobe elemental analysesIsotopic analyses

Seismic/logsCalibration of log dataCalibration of seismic response

1-in whole core

Thin section

Carbonate Core Data

4.13: Core samples present geologists and reservoir engineers with a wealth of information about the reservoir in the immediate vicinity of the well, including wettability.

Figure 4.13

“reservoir wettability is one of many parameters that can be derived from analysis of carbonate core samples. however, core wettability can be modified in several ways before the sample reaches the laboratory.”

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Gravity-dominated flow in a reservoir with layered wettability

Gravity-dominated flow in water-wet reservoir

4.14: Waterflooding recovers only a small proportion of the oil in the oil-wet layers of a mixed wettability reservoir.

Figure 4.14wettability can be inferred from other measurements. for example, strongly water-wet and strongly oil-wet materials display characteristic relative-permeability curves, but the intermediate and mixed wetting states are not a simple extrapolation between the wettability extremes.

At present, there is no method for measuring wettability that can deliver an accurate result. the lack of a definitive test for this vital reservoir characteristic is the driving force behind many ongoing research projects.

Waterflooding and enhanced oil recoveryOil- and water-wet zones can be found within the same reservoir. the challenges for geoscientists and engineers are to define the distribution of these layers and track the changes that occur throughout production.

wettability affects the performance of waterflooding, which can involve significant up-front spending. Imbibition forces, the tendency of a formation to draw in the wetting phase, determine how easily water can be injected and how it moves through a water-wet formation. water breakthrough occurs later during waterflooding, and more oil is produced before the water breaks through in a water-wet reservoir than in an oil-wet reservoir.

waterflooding in reservoirs that contain both water-wet and oil-wet layers can be difficult to control. simulations conducted at the Abu Dhabi regional technology center have shown that only limited amounts of oil can be recovered from oil-wet layers because, although injected water can displace oil from water-wet layers, it displaces very little from oil-wet layers (fig. 4.14). the recovery factors for layered reservoirs can be less than 10%.

Because the impact of wettability extends from pore through to reservoir scale, wettability can affect project economics. wettability influences oil recovery, which is one of the most important quantities in the E&P business, through the parameters Swi and Sor. In addition, the relative permeabilities of oil and water vary with formation wettability. In projects with huge up-front capital expenditure for facilities, such as those in deepwater areas, failure to understand wettability and its ramifications can be costly.

understanding wettability during enhanced oil recovery, when many different fluids are present and moving through the reservoir, will be crucial to ensuring the success of enhanced oil recovery operations.

Sustained efforts in reservoir characterizationnaturally fractured reservoirs present many challenges. the uncertainties relating to the physical structure and the fluid content of the reservoir make fluid flow appear unpredictable. schlumberger has researched and developed a unique combination of modeling and visualization techniques to simulate fracture properties and provide a more complete understanding of reservoir connectivity issues and fluid flow mechanisms. this research effort will continue across a broad spectrum of technical disciplines and geographical locations.

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HiSHaM KHaLiL ZuBaRiHisham Khalil Zubari is petroleum engineering manager for the Bahrain Petroleum Company (Bapco). In 1998, he received the Distinguished Engineer award from the Bahrain Ministry of Labour and Social Affairs. Hisham’s technical interests focus on the management of mature fields, and he is chairman of the Well Testing Committee and the Sponsor of the Corporate Geographical Information System Implementation Project in Bapco.

q: The Bahrain field contains many stacked reservoirs, most of which are carbonate rocks but all quite different. How have field development plans changed over time and what can the experience tell us about other Middle east reservoirs?the Bahrain field was discovered in 1932 and is considered the oldest in the area. Over the years the field’s production has been maintained at a reasonable level with the help of gas injection and advanced lifting mechanisms. Exploring different and more advanced techniques will be crucial for prolonging the life of the reservoir. two years ago, the Bahrain government, through the national Oil and gas Authority, invited international oil companies (IOc) to participate in the development of the field. several IOcs have studied the field and shown confidence in revitalizing the maturing assets. we have conducted detailed assessment and evaluation of several possible development programs to select the one that was most closely aligned with our objectives in targeting difficult reservoirs. this year we are hoping to form a joint venture with an IOc that will address and resolve the challenges.

the maturing carbonate reservoirs in the Bahrain field provide a valuable opportunity for the industry to explore technologies that can increase reserves and production. the Bahrain field is an archetype for fields in the area. finding appropriate solutions for the complex carbonate reservoirs in the Bahrain field will help provide a clearer insight on how to plan secondary and tertiary stage operations for surrounding giant fields. In that sense the Bahrain field is valuable for the petroleum industry in the Middle East carbonates.

q: The main oil producing horizon in Bahrain, the Bahrain group, is oil-wet. What technical challenges and opportunities does this create?the oil-wet Mauddud carbonate reservoir is the main reservoir in the Bahrain group. In theory its residual oil content, which is estimated at 50 –60% of OOIP, could be stripped by chemical

flooding, steam flooding, and microbial treatments. the challenge is to translate the technical successes we have enjoyed in laboratory studies to our field-scale operations in a cost-effective and economically feasible way. this will require large-scale investment and commitment by the government. we plan to test a steamflooding method on the residual oil in the Mauddud reservoir, and we hope this will provide valuable results to build on.

q: is there a significant potential for heavy oil production in Bahrain, and what technologies do you think should be evaluated for this application?the Bahrain field contains more than 1 billion barrels of heavy oil and tar in carbonate reservoirs. unfortunately, the industry has not yet matured when it comes to extracting heavy oil from heterogeneous and tight heavy-oil reservoirs. Bapco, in collaboration with an international oil company, is in the process of setting an aggressive plan to tackle this challenge. we are confident that we will find an effective combination of technologies to help us upgrade these resources into the proven category, and this will require collaboration with IOcs, service companies, and research institutes.

q: How important is research on carbonates for Bapco, and what research directions would you recommend as priorities?Research is the key that will unlock the potential of carbonate reservoirs. the highest priority in my view is to resolve the issue of wettability in carbonates. Ideas such as steamflooding, and microbial and chemical flooding are worth investigation, but the main challenge is to devise a cost-effective method for stripping residual oil from the rock surface, and with higher oil prices this will be achievable.

Another challenge is to develop a numerical simulation of carbonate reservoirs so that field operators can track bypassed oil left in pockets during the secondary and tertiary phases of development. this will require intensive research into the characteristics of carbonate rocks. My third priority for carbonate research would be to optimize the production of heavy oil so that we attain the high levels of recovery that can be achieved in clastic rocks.