SPE 166209

Intelligent Completions And Un-Cemented Liners Combine To Provide A Fully Completed Solution With Zonal Isolation In Norway A.W. Kent, D.W. Burkhead, R.C. Burton, K. Furui, S.C. Actis, K. Bjornen, J.J. Constantine, W.W. Gilbert, R.M. Hodge, L.B. Ledlow, M. Nozaki, A. Vasshus, and T. Zhang, ConocoPhillips

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract This paper describes the design, testing, installation, and performance of the first ‘fully-completed’ well using an intelligent

inner completion inside an un-cemented liner with openhole packers for zonal isolation. The well design concept evolved

from technical challenges associated with completing long cased and cemented laterals in the mature Ekofisk waterflood. The

term ‘fully-completed’ implies full reservoir access along the pay length for production and high rate matrix acid stimulation

using limited entry for fluid diversion within well segments.

The paper covers the development and qualification of custom openhole 7⅝ in. liner components that can handle high

differential pressures and extreme temperature fluctuations, the marriage of this complex liner with a five zone intelligent

completion system, and results from a year of system integration testing. The paper also discusses the strategic placement of

both mechanical openhole and inner string packers based on caliper and drilling logs; challenges met and overcome during

installation; and a remarkable collection of down-hole gauge data that confirms the performance of each component before,

during, and after the stimulation.

The Ekofisk field waterflood began in 1987 and continues to date, exceeding expectations for improved oil recovery while

mitigating reservoir compaction. As the waterflood matures, new wells are more often found partially water-swept. Limited

infrastructure for lifting and handling the high water production has led to increased emphasis on isolating these water-swept

intervals. Cased, cemented and perforated completions have traditionally been used for this service. It has become

increasingly difficult to execute a successful cement job in longer horizontals with 4,000 ft to 8,000 ft laterals where rotation

of the liner is impossible and high effective circulating densities (ECDs) limit rates during cementing. Wide variations in

reservoir pore pressures, often in excess of 2,000 psi difference along the lateral, are typical of the Ekofisk chalk and

exacerbate the difficulties of cementing. As a result, a new method for zonal isolation has been developed to ensure the

success of future infill drilling campaigns.

The design and careful planning that went into the fully-completed openhole un-cemented liner strategy resulted in a

successful field trial and has proven this solution to be an effective alternative to cemented reservoir liners in long horizontals

where zonal isolation is critical. Use of the intelligent well system (IWS) allowed offline acid stimulation without rig, coiled-

tubing, or wireline intervention. What would have traditionally been a significant water producer, with three water-swept

zones totaling nearly 2,000 ft across a 4,000 ft reservoir section, has turned out to be one of the best oil producers in the field

with nearly zero water cut. Production results show high productivity with highly negative acidized completion skins.

With large investments in intelligent completions to provide zone-specific inflow control and water shut-off, isolation outside

the liner becomes much more important. Over recent years, the Ekofisk wells have illustrated the difficulty of achieving

effective cement along lengthy reservoir targets. The openhole fully-completed solution combining an accessorized un-

cemented liner with an inner intelligent completion string will allow operators to push the limits in terms of lateral length

while maintaining full control over producing and non-producing zones.

Introduction The Ekofisk field is located in the central part of the North Sea off the south western coast of Norway. The sea depth in the

area is 230 to 250 ft. The Ekofisk field produces from the naturally fractured Ekofisk and Tor chalk formations of Early

Paleocene and Late Cretaceous age. The reservoir chalk has high porosity, but low permeability with an oil column of

approximately 1,000 ft at depths ranging from 9,000 to 11,000 ft below sea level. Ekofisk was originally developed by

pressure depletion and was expected to have a relatively low recovery factor of approximately 17%. Since then, limited gas

injection and comprehensive water injection have contributed to a substantial increase in oil recovery. Large scale water

injection started in 1987, and experience has shown that water displacement of the oil has been more effective than expected,

with current projections indicating a recovery factor of approximately 50%. In addition to water injection, compaction of the

soft, high porosity chalk provides an additional recovery mechanism. This reservoir compaction has resulted in subsidence of

the seabed, which is now more than 30 ft in the central part of the field. As a consequence of water injection, the rate of

subsidence has slowed significantly; however, current projections indicate that subsidence will continue at a few inches per

year for the remaining life of the field. Hermansen (2008) provides a more detailed account of how the waterflood has

impacted the Ekofisk field development.

Completion practices at Ekofisk have evolved over time. Initial vertical wells were cased, perforated and acid fractured. As

horizontal wells were introduced to the field, the long horizontal sections were also cased and cemented. The heavy-walled

production liners were then perforated in 10 foot clusters, typically at one shot per foot, every 200 to 500 ft along the length

of the lateral. The wells were then stimulated with acid by bullheading alternating stages of pad and acid with ball sealers for

diversion. These cluster perforation designs typically showed high initial productivity followed by sharp production declines

(Snow and Hough 1988). Production logging results indicated that many of the perforation clusters were not effectively

stimulated, with some clusters, typically at the heel of the well, receiving far more acid than required and others receiving

little or no acid. This ineffective treatment diversion was often made worse by performing remedial acid treatments by

bullheading additional acid into the wells, generally into the previously stimulated intervals without reaching the un-treated

perforation clusters. The large volumes of acid placed into a limited number of perforation clusters weakened the rock and,

coupled with reservoir compaction and associated chalk movement, led to liner buckling. Liner buckling then led to the loss

of zonal access and in extreme cases, pipe failure and loss of the well. Restricted access to the reservoir liner impeded well

intervention and remedial opportunities. Figure 1, below, illustrates the correlation between high acid volume and casing

failures.

Figure 1—Sample of 28 wells. Each bar represents a well.

As shown in the figure, wells with acid injection volumes greater than 100 bbl/station have a much higher liner deformation

and failure rate than wells stimulated with lower acid volumes per station. The high failure wells are all cluster perforated

wells where large volumes of acid were injected into the small perforation clusters.

To improve acid stimulation and reduce casing deformation and well failures, a new class of wells was introduced to the

field. These new, “fully-completed” wells were perforated along the entire horizontal section and used limited entry

techniques to distribute acid more evenly over the reservoir intervals. Perforations were generally spaced at one hole every

ten feet of reservoir net pay along the horizontal section with stimulation volumes in the order of 20 bbls of 28% HCl acid

per perforation. These new completion techniques proved successful in providing high productivity completions with low

well failure rates. Post-stimulation skin values have been found to be in the -4 to -4.5 range (Furui et al. 2012, Parts I and II),

2 SPE 166209

while liner deformation and well failures have decreased as shown in Figure 1, above. In this figure, the wells stimulated with

less than 100 bbl/station are the fully-completed wells.

The new fully-completed designs were first implemented in horizontal wells with cemented liners, but as confidence in the

designs increased, conceptual planning moved to openhole designs with un-cemented liners. An early field trial of the fully-

completed well design in an openhole, un-cemented liner completion proved favorable with no liner deformation seen after

three years of production. To further improve the fully-completed well designs, it was desired to combine the benefits of a

surface-operated, Intelligent Well System (IWS) for down-hole flow control with limited entry diversion to provide uniform

acid distribution along pay intervals in an un-cemented liner. While primarily designed to assist in the initial acid

stimulation, these benefits would help achieve more effective diversion during remedial acid and scale inhibitor treatments

later in the life of the well. This led to the Ekofisk 2/4-B-19C (hereafter referred to as ‘B-19C’) well design.

The objectives of the new B-19C openhole un-cemented liner completion are to

1. Enhance well productivity and recovery

2. Provide water shut off capabilities and selective zone access for scale/acid treatments

3. Allow stimulation and remedial scale treatments without rig, coiled tubing, or wireline intervention

4. Provide adequate liner stability to improve well access and prolong well life

Functional Requirements for the Un-Cemented Liner and Intelligent Completion As the B-19C un-cemented horizontal completion team worked on the design, a number of functional requirements were

established to improve well performance, reservoir management, and reservoir liner integrity. These functional requirements

include:

• Un-cemented reservoir liner with openhole packers, allowing for effective hydraulic isolation of water-swept intervals

while allowing high pressure/high rate acid stimulation and oil production from target oil zones.

• Full completion of entire length of productive zones, utilizing high-rate matrix acid stimulation, in lieu of acid fracturing,

to improve post-acid completion skin, improve well productivity, and minimize liner deformation for extended well life.

• Ability of reservoir drilling fluid system to allow for effective acid cleanup of mud and filter cake without causing

compatibility issues.

• Surface controlled access to productive zones in the horizontal lateral to allow

o Unlimited down-hole valve manipulations (open/close) without wireline or coiled-tubing intervention

o Flow control into and out of each zone during stimulation, production, and scale inhibitor squeezes

o Uniform acid stimulation of entire length of each zone

o Uniform scale inhibitor treatments and remedial acid treatments along entire length of each zone

o Well test flexibility

o Measurement of zonal pressure/temperature data

• Ability to run the pre-drilled reservoir liner as a solid, pressure-sealed liner to allow

o Elimination of an inner string, as normally required with a conventional pre-drilled liner

o Ability to circulate and maintain well control while running the IWS completion string

o Pressure activation of all liner components, including openhole packers at one time

o Elimination of tubing conveyed or wireline perforating operations

• Allow for successive acid stimulation of each zone after moving the rig off location, without the need for wireline or

coiled-tubing intervention.

• Ability of completion equipment to resist pipe movement and stress failure as a result of thermal and hydraulic loads

induced during stimulation, water injection, or production operations.

• Ability to handle stimulation differential pressures between zones of up to 5,000 psi.

• Ability to handle temperature change of 200oF during stimulation.

Design Features of the Un-Cemented Liner Completion The drilling of the 9½ in. horizontal lateral in the Ekofisk and Tor chalk reservoirs would be performed using an 11 ppg oil-

based (“oil-based” indicates inverted phase) emulsion containing 60 lbs/bbl calcium carbonate. This system is unique in that

it lays down an oil-wet calcium carbonate filter cake, but can be converted to a water-wet filter cake once acid is applied and

the pH is lowered (Lim et al. 2011). The water-wet filter cake, consisting almost entirely of calcium carbonate, can be

dissolved with HCl acid allowing for effective stimulation of the entire completion length.

After drilling the reservoir section, a dedicated trip with a stiff roller reamer assembly would be made. This roller/reamer

assembly was designed to imitate the stiffness and geometry of the reservoir liner and liner components as closely as

possible. The purpose of this assembly was to smooth out any doglegs and remove any problematic ledges in the openhole

section. This reamer run would also provide a field estimate of drag for calibrating torque and drag models before running the

reservoir liner.

SPE 166209 3

Once the wellbore was conditioned, a 7⅝ in. 51.2 lb/ft Q125, metal-to-metal seal, 6.125 in. drift, openhole liner system

would be run to total depth (TD) in the 9½ in. horizontal lateral on drill pipe.

Figure 2—A conceptual drawing of the un-cemented liner showing the relative positions of liner components.

A number of components would be run as part of the liner design to meet the functional requirements of the completion

system (Fig. 2, above). All components were designed with a drift diameter equal to or larger than the 6.125 in. drift

diameter of the 7⅝ in. liner. An expanded view of the 7⅝ in. liner is provided in Fig. 2 to show the relative position of these

liner components. A description of each 7⅝ in. openhole liner component is provided below to explain its purpose.

Liner Hanger Packer – the liner hanger packer was designed to hold large axial loads in both directions and to provide

hydraulic isolation above and below the liner hanger during the life of the well. The liner hanger packer would be activated

hydraulically using a ball drop sub as soon as the liner was landed on bottom.

Toe Isolation Valves – two valves would be run in series at the toe of the liner. Both valves would be run in the open

position while running in hole to allow for pipe fill. A battery powered, electronic type valve would be run on bottom as the

primary valve and set to automatically close on a timer an estimated 12 hours after reaching TD. Pressure activation would

allow for the valve to be re-opened if premature closure occurred. A ball drop type valve would be run above the electronic

valve as a contingency, in case the electronic valve did not close as planned. The main function of both toe valves was to

provide permanent hydraulic isolation in both directions once closed. During actual well operations, the primary valve

worked as intended and the backup valve was not activated.

Metal Expandable Openhole Packers – these specially designed openhole packers (Hazel et al. 2013) would be positioned

in the liner string to provide hydraulic isolation between strategically defined zones, intervals, in the horizontal section.

Design requirements called for the packers to provide hydraulic isolation at up to 5,000 psi zone-to-zone differential pressure

in openhole sizes up to 10½ in. Porosity and resistivity responses generated by Logging-While-Drilling (LWD) tools during

the drilling process would be used to differentiate pay zones from zones that had been swept by the waterflood. The entire

well team was involved in determining which zones required isolation, based on the location of faults, caliper data, porosities,

water saturations, and pressure data. Two openhole packers were placed at the ends of each zone to enhance isolation

performance during stimulation. The openhole packers would be set hydraulically by pressuring the entire length of the liner

to a pressure differential of 10,000 psi.

The openhole packers were designed to provide hydraulic isolation between all zones during the acid stimulation and

production phases. The key challenge facing this design was the stimulation design case of injecting 75○F acid at 60 bbl/min.

Because of the tremendous forces exerted by the large thermal and hydraulic loads during acid stimulation, special

consideration was given to allowing for liner contraction and stabilization of the openhole packers. Without such provisions,

tensile forces within the 7⅝ in. liner string would exceed 600,000 lbs. Such high tensile forces could cause the openhole

packers to slip along the formation, resulting in possible acid leakage around the packers and loss of ability to seal in the

open hole.

4 SPE 166209

Rock Anchors – rock anchors were designed to minimize liner and packer movement during stimulation and production.

Each rock anchor would consist of two sets of three independent slip segments that were designed to tolerate variations in

openhole diameter and shape. A single rock anchor was positioned adjacent to or between each set of openhole packers in

near-gauge hole, so as to provide additional anchoring support of up to 200,000 lbs for the packers. The anchors would be

positioned to minimize the risk of acid exposure during stimulation, since acid would likely weaken the rock in which the

anchors were set. The rock anchors were designed to be hydraulically activated at 3,000 psi.

Expansion Joints - one expansion joint would be run near the middle of each zone to relieve tensile loads that were expected

to develop during stimulation, whether from the 7⅝ in. liner or from the inner completion. The expansion joints were

designed to release at 5,500 psi differential pressure during the openhole packer setting process. Expansion was not possible

during the setting process, since the rock anchors were fully set and both ends of the liner were additionally confined by the

liner hanger and the end of the well. The expansion joints were designed to expand up to a maximum of 36 in. due to cool-

down during stimulation. Actual movement of the expansion joints in the B19 completion was expected to be less than 18 in.

in all cases, based on the chosen length of each zone.

Acid Soluble Plugs (ASP) – these plugs (Fig. 3, below), served to

• allow for running of a pressure-tight liner, thus enabling the pressure activation of all liner components

• eliminate the need to perforate the liner, providing reservoir access by dissolving the plugs with acid

• prevent fluid loss while running the intelligent inner completion string. Each of the plug’s ports was drilled with a

0.20 in. entrance hole to create a limited entry effect during stimulation. The diagrams below illustrate the geometry

of the liner ports and acid soluble plugs

Figure 3—Cross-section of acid soluble plug installed in 7⅝ in. 51.2 lb/ft liner.

Acid Circulating Valves (ACV) – ACVs would be included at one end of each productive zone to allow for acid to be

circulated into the wellbore after running and setting the intelligent completion system. The purpose of the acid circulation

process is to effectively place acid along the target interval and dissolve the acid soluble plugs described above. With the

plugs dissolved, the stimulation process could proceed.

The ACVs were run in the closed position, allowing for a pressure-tight liner while running in hole and the subsequent

openhole packer setting process. Dual ACV shifting tools were run as part of a subsequent liner cleanout trip. Below the

shifting tools, a specially designed valve position logging tool with memory gauges was run to verify that the ACVs had been

successfully shifted to the open position. A closed ACV would have prevented acid from being spotted to dissolve the acid

soluble plugs, thus preventing access to the zone of interest. Rupture disks, installed in the ACV flowports, prevented fluid

losses until the intelligent completion string was safely in place. Figure 4 shows a diagram of the ACV, an ACV shifting

tool, and the memory logging tool.

SPE 166209 5

Figure 4—Drawing of two ACVs. On the left, an ACV shifting tool is shown engaged in the ACV shifting profile. On

the right, a shifted ACV is shown with a logging tool. The logging tool senses the exposed antenna thereby confirming

the ACV position.

IWS Tubing String – The B-19C upper completion configuration was dictated by two requirements: reservoir production

zonal control and stimulation zonal control. The ability to selectively shut off water swept sections was considered critical

for well performance and reserves recovery, and has proven to be invaluable. This entailed use of a dedicated IWS string with

multiple control valves and packers to be run inside the 7⅝ in. production liner. Stimulation rates of 60 bbl/min far exceed

production rates, demanding maximum through-bore diameter. Within the 7⅝ in. 51.2 lb/ft un-cemented liner’s 6.125 in.

drift, 3½ in. flow-control components and 4½ in., 12.6 lb/ft tubing were the largest components possible, while still

accommodating control line flatpack running on the outside of the IWS string. Above the liner top, the 10¾ in. production

casing allowed upsizing to 5½ in., 17 lb/ft and 20 lb/ft tubing. The Annular Safety Valve (ASV) and Subsurface Safety

Valve (SSSV) were similarly 5½ in. Sizing of upper completion components was less influenced by production criteria than

by stimulation requirements.

Flow Control Architecture – The existing 18¾ in. 10,000 psi wellhead limited the penetration count at the tubing hanger to

eight lines. A five zone IWS system, plus down-hole pressure and temperature (DHPT) gauges, a tubing retrievable

subsurface safety valve (TRSSSV) and an annular safety valve (ASV), required too many lines for the tubing hanger when

utilizing a direct hydraulic control architecture. As such, a multiplexed control architecture was employed, synchronizing two

interval control valves (ICV) on a single line with Single Line Switch (toggled) functionality. As a result, the five production

zones could be controlled by four hydraulic lines in total, lowering tubing hanger penetration count from nine to eight. Figure

5, below, illustrates the flow control architecture for the well with the eight lines at the tubing hanger (far right).

Figure 5—IWS inner completion control architecture. The tubing encapsulated conductor (TEC) is an electrical cable

that transmits down-hole gauge data. All other lines shown in the figure are hydraulic control lines.

Feed-Through Production Packer – A 10¾ in. x 5½ in. feed-through production packer was installed above the un-

cemented liner. This ISO14310V0 rated packer is designed for acid stimulation, production and gas-lift service; each

component accommodated control lines for down-hole IWS functionality. The 5½ in. production tubing string was crossed

Zone A

PackerZone A

HCM-A

Zone B

Zone C

Zone D Zone E

Production

Packer

ASV

Tubing Hanger

6 SPE 166209

over to 4½ in. directly below the production packer. Five out of seven line feed-throughs were required to accommodate the

four hydraulic control lines and one electronic gauge line (Fig. 5).

Zonal Isolation Packers – 7⅝ in. x 3½ in. feed-through zonal isolation packers were set in blank sections between the

openhole packers separating reservoir net pay intervals. Up to six feed-throughs were utilized, depending on the zone control

architecture in each packer’s location (Fig. 5).

Dual DHPT Gauge Subs – down-hole pressure and temperature measurement was considered essential for stimulation and

production control. Quartz oscillator transducer pressure gauges were installed in each zone, which enabled reservoir

characterization and stimulation diagnostics to be performed after acid injection. In addition, the gauges provide early

identification of water breakthrough, allowing valve positions to be configured for optimal producing conditions.

Control Line/Flatpack – Protection of control lines was a critical design requirement. Encapsulation of control lines,

eliminating bare line exposure to the annulus, was the goal. Protection of lines in areas of high velocity was of particular

concern. Cross coupling clamps were installed on every joint and specialty clamps were employed in locations such as

SSSV, ASV and the Tubing Hanger. Incoloy-825 control line was specified throughout the system. All control line

terminations utilized state-of-the-art metal-to-metal fittings with isolated tension anchoring to protect control system integrity

in the event of external pressure or induced tension during installation.

Interval Control Valves (ICV) – Variable position sliding sleeve valves were installed in each zone. Full tungsten carbide

trim was utilized for tolerance of extreme stimulation velocities. These ICVs operate by indexing sleeve actuation, providing

14 valve positions from fully open to fully closed. Synchronization of sleeves between two ICVs provides multiple control

combinations: both zones closed, both zones full open, one zone open and one closed, etc. Figure 6, below, illustrates the

wellbore configuration.

Contingencies –Intelligent Well ICVs offer a mechanical alternative in the event remote control is not available. Profiles are

present in all trim to mechanically shift a valve, typically with a wireline stroker. Gas lift valves and the annular safety valve

were installed in the upper tubing string as a contingency for flow assurance.

Figure 6—A conceptual drawing of the un-cemented liner with IWS inner completion string showing the relative

positions of completion components.

Equipment Testing and Modeling Extensive tubular stress modeling was performed on the IWS tubing string for the entire well, but extra effort involving an

expert consulting company was placed on the tubing section between the production packer and the toe of the well. This area

involved the most complexity and the highest risk, because a new tubular design involving new components, multiple zones,

and new loading conditions was being simultaneously implemented. The well team identified at an early stage that high

tensile loads would develop in this section of the well due to thermal cooling during high rate stimulation with cold treating

fluids. Ballooning forces, caused by high bottomhole treating pressure conditions combined with partially depleted zones,

would further increase these already severe tensile loads.

SPE 166209 7

A robust modeling tool that accounted for thermal effects was used to model the combination of these treating conditions. As

suspected, modeling results validated the severity of the combined loads and was very useful in defining the maximum down-

hole treating pressure criteria that could be tracked in real time to avoid tubular failures.

To initiate the acid stimulation treatment, the acid must breach the aluminum plugs and traverse the liner by openhole

annulus to reach the chalk reservoir. Although the chalk is highly acid soluble, there were concerns that the oil based mud

(OBM) occupying the annulus and the OBM filter cake on the borehole wall could impede acid/chalk contact stimulation

treatment. To minimize the potential of the OBM impeding the access of the acid to the chalk reservoir, an acid-reversible

OBM (Lim et al. 2011) was used to drill the reservoir section. This oil-external mud system was designed to be reversed to a

water-external state on contact with acid to allow ready access of the acid treatment stage to the filter cake and chalk

reservoir. Laboratory testing of the reversible OBM was conducted to optimize the formulation with regard to drilling

performance (rheology, fluid loss control, thermal stability, etc.) and acid reversibility. The results shown below (Fig. 7) led

to the selection of mud formulation 2 for this well.

Figure 7—Effect of a 15% hydrochloric acid (HCl) solution on filter cake samples and an acid soluble plug. These

tests were conducted at the expected reservoir temperature of 275°F.

Among the innovative design features of the fully completed, un-cemented liner were the Acid Soluble Plugs (ASP). These

plugs must provide a reliable pressure seal until the liner and IWS equipment were installed and the acid stimulation was

ready to be executed. At that time, the ASP must be dissolved to provide access to the reservoir. A range of plug designs

were reviewed and tested. Aluminum was selected as the best material for this application, as it is readily soluble at

atmospheric pressure and reacts vigorously with 15% HCl. Initial testing of the ASP prototypes at 150-250°F and 300 psi

pressure indicated the plugs could be rapidly removed with 15% HCl. However, testing at higher pressure revealed that the

reaction rate was pressure dependent and the time to breach the plug with acid could be excessive for thick-wall ASP designs.

To accurately predict the time required to remove the ASP with acid, an extensive testing program was initiated to measure

acid break-through times at down-hole pressure and temperature. Numerous ASP designs were tested with various acid

formulations until a design was identified that provided the required pressure integrity and a companion acid formulation was

developed to give an acceptable break-through time of approximately 17 minutes at the formation temperature of 275°F (Fig.

7, above).

The rock anchors, expansion joints, ACVs, and openhole packers were new designs with no field runs. As such, they required

rigorous qualification programs to ensure they survived the trip in hole and remained functional before, during, and after the

high-rate matrix acid stimulation. The following are examples of tests performed as part of the qualification programs:

• ACV flow testing to ensure sufficient flow area for spotting of acid for aluminum plug dissolution and to calibrate

discharge coefficient required for post-stimulation analysis (Fig. 8, below).

• Compressive and tensile load tests of rock anchors set inside cemented test fixture to replicate expected unconfined

compressive strength (UCS) of chalk borehole (Fig. 9a, below).

• Expansion joint function testing in mud with high solids content and 5°/100ft dogleg severity at the expected reservoir

temperature of 275°F.

• Comprehensive pressure and temperature cycle testing of openhole packers to simulate pressure setting, stimulation,

production, and depletion scenarios in hole sizes up to 10½ in. diameter.

8 SPE 166209

Figure 8—Pressure drop vs. rate during ACV flow testing. The actual measurements matched calculations for a

discharge coefficient (C-factor) of 0.66.

In addition to the qualification programs mentioned above, multiple contingencies were prepared in case the toe valves did

not function as intended or a leak developed before all liner components could be set. To ensure compatibility with this

unique liner design, the following system integration tests were performed:

• Pump through test of toe valve ball through ACV internal recess (Fig. 9b, below). The tests indicated that a pump rate of

5 bbl/min was required to move the 1.7 SG ball out of the recess, and 3 bbl/min for the 1.3 SG ball.

• Drifting of liner components with retrievable hook-wall packer.

• Drifting of liner components with cup type straddle packer assembly (Fig. 9c, below), including rotation-operated drag

block ball valve (Fig. 9d, below).

Figure 9—Images of the (a) rock anchor cemented pull test fixture, (b) toe valve ball/ACV pump through test, (c) cup

type straddle packer elements, and (d) rotation-operated drag block ball valve.

Qualification of Intelligent Well Valves To achieve successful acid stimulations in Ekofisk, high treating rates in the order of 60 bbl/min are employed to force the

acid deep into the chalk formation. A benefit of intelligent well technology is that it allows surface controlled isolation or

access to a specific interval allowing selective stimulation of the reservoir. Unfortunately, no test data was available to

determine the reliability of the Intelligent Well Completion System (Intelligent Well System, or IWS) during the high rate

acid treatment and during subsequent production operations. To determine the performance of the Intelligent Well System

under well treating conditions, a Computational Fluid Dynamics (CFD) model was created to predict the velocity and

pressure losses across the specific geometry of the IWS valve. After a number of model runs, it was determined that the

maximum allowable pressure drop of 300 psi at 60 bbl/min could not be avoided without a substantial redesign of the

hydraulic valve. As a result, additional CFD work was conducted and a final compromise of 500 psi maximum differential

pressure across the valve at 60 bbl/min was accepted. After completing the CFD modeling work, a full scale flow test of the

SPE 166209 9

control valve and associated equipment was scheduled.

Requirements for the flow test included:

• Determine if the system would remain functional after exposure to a flow rate of 60 bbl/min.

o Would pressure losses be excessive at design rates, limiting acid stimulation effectiveness?

o Would components be damaged by vibration under high velocity flow conditions?

o Would components be damaged by erosion during high rate flow?

• Validate the CFD model by measuring pressure drop across different areas the system.

o Determine pressure drop across the hydraulic valve for water flow and for water with friction reducer.

o Determine pressure drop across clamps and control lines in the liner for water flow and for water with friction

reducer.

Figure 10—Diagram of the flow loop designed to test and measure friction pressure losses across various IWS

components inside the liner during high rate matrix acid stimulation. Flow path ‘1’ represents friction pressure losses

through intervals upstream of the zone being treated. Flow path ‘2’ represents annular friction pressure losses in the

zone being treated.

To run these tests, a flow loop was designed to allow flow straight through the valve ID with the valve closed, or through the

open valve into the annulus (Fig. 10). The flow loop included a hydraulic valve with an internal diameter of 2.75 in. and

5.940 in.2 of flow area through the valve ports in the open position. A 3½ in. gauge mandrel with dual pressure and

temperature sensors was included upstream of the hydraulic valve to measure the differential pressure across the valve ports.

Other pressure points included measurements of the pressure loss across a cross-coupling clamp and the annular pressure loss

between the tubing and casing. To validate friction pressure loss and flow rate measurements, two full tubing joints and

pressure gauges were installed downstream of the test fixture. By comparing this measured pressure loss to published

empirical data, the flow rate could be confirmed and the impact of adding friction reducer was established for various rates.

Testing was completed with full functionality of the dual sensor gauges and hydraulic valve. However, with the test fixture

disassembled, it was observed that the control line by-pass protector plate had broken in two. Vibration had caused the small

retaining cap screws to back out of their tapped holes, thereby allowing the protector plate to enter the flow stream and

separate. A simple redesign of the plate retention method proved successful at preventing vibration related damage. The

image in Fig. 11a, below, shows the broken protector plate after the initial post-test inspection. To the right is the new design

(Fig. 11b), which survived a full hour of annular flow at 60 bbl/min.

Figure 11—Photos of two control line protector plates installed at the IWS valve flowports. (a) The damaged

10 SPE 166209

protector plate from the first IWS flow loop test. (b) The retaining mechanism was redesigned and successfully

prevented damage to the protector plate in a subsequent flow test.

Operational Highlights The complex nature of the naturally fractured chalk in the Ekofisk field makes it challenging to predict the pattern of the

waterflood, leaving the details of the final completion to be decided only after the well has been drilled. A sophisticated

logging plan was implemented to better characterize the wellbore and improve hole conditioning efforts. Among the LWD

tools was a Deep Directional Electro-Magnetic (DDEM) tool (Constable et al. 2012) which helped with trajectory planning

while drilling. Approximately halfway into the Tor formation, the DDEM readings indicated that the well was being drilled

into the lower, wet layers of the target Upper Tor formation, near the border of deeper Tor layers. After passing through a

fault, higher resistivity values were seen above the well and the decision was made to increase hole angle from 90° to 94°,

steering up and into oil filled formation. The presence of sub-seismic faults and layers with high water saturations also plays

an important role in the decision on where to blank off sections with openhole packers and solid liner joints versus where to

expose the liner to the reservoir using acid soluble plugs. Figure 12, below, shows the point at which the decision was made

to build to 94° in an effort to remain in the oil saturated Tor interval.

Figure 12—DDEM image superimposed over the associated reservoir model image. Distinct changes in the DDEM

image correlate well with fault lines captured in the model. The narrow black line is the well path, which was adjusted

while drilling to access the oil saturated Upper Tor interval.

Formation pressure points in the shallower Ekofisk formation, at the heel of the horizontal well, revealed lower than expected

reservoir pressures. Anticipating higher pressure in the deeper Tor formation, LCM and wellbore strengthening techniques

were utilized to manage mud losses to the low pressured heel interval. Drilling concluded 500 ft shallower than planned due

to increasing formation pressure and water saturations. Maximum pressure differential across the reservoir had increased to

1,600 psi, which would make cementing the liner very challenging. LWD logs indicated five pay zones of 1,400 ft in total

and four water saturated intervals making zonal isolation absolutely critical for long term production. In terms of the basis of

design, the B-19C well was an ideal candidate to field trial the un-cemented liner technology for its capability to provide

zonal isolation. A five zone completion was selected with two openhole packers between each adjacent interval for zonal

isolation in open hole.

Pipe conveyed, multi-arm mechanical caliper logs revealed that most of the 9½ in. open hole was well gauged with hole

diameter ranging from 9.7- to 10-in., well within the openhole packer specifications. Results from LWD caliper readings

were in very close alignment with mechanical logs. A stiff reamer assembly was then run to bottom to remove any localized

doglegs or ledges that might prevent the 9.2 in. maximum OD liner equipment from reaching TD. The images below show

caliper log comparisons of three washout (in red) sections and the under gauge (in blue) toe section. These logs were

carefully evaluated to determine the optimal openhole packer setting depths.

SPE 166209 11

Figure 13—Caliper log comparisons for three washout (red) sections and the under-gauge (blue) toe section.

The 7⅝ in. un-cemented liner make-up and running operation went well until the last 800 ft from TD, where sticking

occurred and the string was worked in order to reach TD. Actual hook loads were plotted against torque and drag modeling

results while the liner was being run (Fig. 14, below).

Figure 14—Measured hook load values (orange) compared to simulated values. The actual hook load diverged from

simulation results at approximately 14,000 ft MD, the same depth at which the build to 94o was made.

After the 7⅝ in. liner was run to TD and liner hanger was successfully set, a retrievable, hook-wall service packer was run

and set immediately below the liner hanger for pressure setting all openhole equipment. A leak developed at 8,200 psi while

attempting to pressurize the liner and prevented us from reaching the designed 10,000 psi setting pressure for the openhole

packers. The service packer was then re-set at different depths and the liner leak was located near an openhole packer at the

top of Zone B. An injection test with mud indicated the size of the leak matched the flow area of the openhole packer setting

ports. Before retrieving the service packer, it was used to pressure set all liner components below the leak with 10,000 psi. A

cup type, straddle-packer assembly was then run as per the contingency plan and proved successful in setting all 17

remaining pressure activated liner components located above the leak. Subsequent testing and investigation of the openhole

packer design has led to improvements that further minimize the risk of failure.

12 SPE 166209

A five zone Intelligent Well System (IWS) inner string was then successfully installed with full functionality of hydraulically

controlled valves, mechanical isolation packers, and pressure and temperature gauges for each interval. Due to the known

liner leak at the top of Zone B, it was decided to spot 15% HCl through the valve at the bottom of the IWS string across

zones A and B to dissolve the aluminum plugs before setting the isolation packers. This was in lieu of relying on bursting the

ACV rupture disks to establish the required flow path after setting the isolation packers.

The isolation packers were set and, as expected, the pressure in each zone diverged from equilibrium to approach their

respective interval reservoir pressures (Fig. 15, below). This implied that every stage contained some aluminum plugs already

dissolved by the 15% HCl acid. It also confirmed the status of positive zonal isolation in the open hole. The pressure and

temperature data from each zone proved to be invaluable from all planned events and even some unplanned events.

Figure 15—Measured annulus pressure vs. time from five IWS zone gauges during the isolation packer setting

process. Pressure diverge at the moment the isolation packer elements make contact with the 7⅝ in. liner ID.

Acid Stimulation Results After moving the rig off location, lines were laid to the well and a dedicated stimulation vessel moved into position for the

acid treatment.

As noted in the previous sections the Ekofisk B-19C well encountered a number of oil and water intervals. After reviewing

the LWD logs, the completion liner was set up to stimulate five oil zones and to isolate wet zones with openhole packers.

This completion design is summarized in the figure below.

Figure 16—Well trajectory and log-derived oil and water saturation predictions.

Eko B19C Isolation Packers Set - 5 Zones Annulus Pressure

3200

3300

3400

3500

3600

3700

3800

3900

4000

4100

4200

Time

Pre

ssu

re (

psi)

Ann A Ann B Ann C Ann D Ann E

SPE 166209 13

Each completion interval (A, B, C, D and E) was equipped with an IWS assembly consisting of a surface controlled valve

providing flow access to the formation and pressure and temperature gauges ported to tubing and annulus (Fig. 17a).

Figure 17—Sequence diagram showing (a) the relative position of zone flow control and isolation equipment, (b) the

initial acid circulation path through the burst ACV rupture disks, and (c) high rate matrix acid stimulation through

the dissolved plug holes and ACV ports.

Each zone was selectively stimulated starting from Zone E (heel zone) to Zone A (toe zone) using the IWS flow control

valves.

For each treatment, the IWS valve in the treatment zone is opened. Tubing pressure is then increased to break the rupture

discs in the ACVs allowing fluid displacement to the target interval. The initial fresh water filling the tubing is followed by a

15% HCl/Mutual Solvent mixture pumped at low rate (Fig. 17b).

Acid pumping continues until the entire 7⅝ in. liner x IWS string annulus has been displaced to acid. This places the 15%

HCl/Mutual Solvent acid system in direct contact with the Acid Soluble Plugs (ASP) which seal the holes in the 7⅝ in. liner

and isolate the formation. The acid soluble plugs are then soaked for a few hours depending on down-hole temperature while

leak-off is monitored to determine the rate of plug dissolution. The HCl/Mutual Solvent acid system is then displaced with

freshwater and an injectivity test pumped at maximum rate consistent with well pressure limits. At the end of the injectivity

period, a hard shut-down is conducted to determine the instantaneous shut-in pressure (ISIP) and allow calculation of the

number and equivalent flow area for the dissolved acid soluble plugs (ASPs). If sufficient flow area has been exposed by the

acid then the main acid treatment can proceed as planned (Fig. 17c). If the flow area is deemed insufficient to pump the main

acid treatment then another HCl/Mutual Solvent treatment is pumped and another soak and injectivity step is conducted.

Table 1 summaries ASAP dissolution results after soaking with the 15% HCl/Mutual Solvent system and after pumping the

main acid treatment with 28% HCl. The average open perforation area was estimated to be 44% of the design area after the

15% HCl/Mutual Solvent soak process. This was slightly lower than our target open area of 67% prior to commencing the

14 SPE 166209

main acid treatment. However, after the main acid treatment, the average plug open area rose to approximately 69% of the

design area. Assuming all of the acid soluble plugs have been at least partially dissolved, the average hole diameter is

estimated to be 0.13 in. after the 15% HCl/Mutual Solvent soak process, and 0.17 in. after the main 28% HCl acid treatment

compared to the 0.20 in. design diameter. Note that all these calculations are based on a discharge coefficient (C-factor) of

0.80.

TABLE 1–B-19C ACID SOLUBLE PLUG OPENING RESULTS

ACV Acid Soluble Plugs Total After Soaking After Main Acid Treatment

Stage Zone (holes) _____(num)_____ holes (% of holes open) ___ (% of holes open)___

1 Zone E 4 21 25 38 % 85 %

2 Zone D 4 7 11 67 % 70 %

3 Zone C 4 35 39 38 % 67 %

4 Zone B 4 63 67 39 % 66 %

5 Zone A 4 56 60 38 % 58 %

After dissolving the acid soluble plugs, the flow path for the 28% HCl used in the main acid treatment is through the acid

soluble plug holes (Fig. 17c). The acid exits the 7⅝ in. liner x IWS string annulus through the 0.20 in. acid soluble plug holes

and the four ACV holes at the bottom section of each treatment interval. As in a conventional cased hole limited entry

treatment, frictional pressure losses due to high velocity flow through the small plug holes limit the amount of fluid exiting

through any one point in the liner, thereby distributing flow more evenly along the openhole treatment interval. At design

acid rates of 0.7 to 1.3 BPM/perforation, average fluid velocities discharging through the 0.20 in. holes in the liner and into

the openhole range from 300 to 550 ft/sec and provide perforation pressure losses in the 1,000 psi to 3,000 psi range. These

high perforation pressure losses are far greater than the frictional pressure loss due to flow along the 7⅝ in. liner x 4-1/2 in.

IWS string annulus and are also greater than formation breakdown and treating pressure differences along the openhole

completion interval.

The main acid treatments consisted of pumping 75 gallons of 28% HCl acid per foot of completion interval at high rate

followed by approximately 150 gallons of fresh water overflush per foot of interval. At design pump rates, down-hole

pressures at the reservoir face typically start out at or above formation parting pressure and very quickly drop below fracture

pressure as acid enters the chalk formation. This pressure behavior indicates that the bulk of the acid stimulation treatment is

pumped under matrix injection conditions conducive to wormholing of the near-wellbore chalk reservoir. A pressure plot of

a typical zone treatment is provided in Figure 18, below.

Figure 18—High rate matrix acid stimulation data vs. time for Zone B.

0

20

40

60

80

100

120

140

160

180

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

480 490 500 510 520 530 540 550 560

Slu

rry ra

te, b

pm

We

llhe

ad d

en

sity

, pp

gF

rictio

n R

ed

uce

r Co

ncentr

atio

n, g

al/M

ga

l

Pre

ssu

re, p

si

Time Elapsed, min

Ekofisk 2/4-B-19C Zone B Treatment

Annular Pressure

Fracture Closure Pressure

Reservoir-Face Pressure

Rate

Wellhead Density

Friction ReducerConcentration

Acid Injection @ Reservoir Face

Acid at ICV

Acid at ACV

SPE 166209 15

As shown, bottom hole pressure at the reservoir face is above formation parting pressure as the acid is pumped down to the

reservoir. Once the 28% HCl acid reaches the chalk face/reservoir face, pressure rapidly drops below fracture pressure and

into the matrix injection realm. As the acid wormholes through the chalk formation, reservoir face pressure continues to

decline as pump rate increases. This injectivity improvement can be used to calculate skin evolution during the course of the

treatment in a manner similar to that introduced by Pacaloni and Tambini (1993) and later extended by Hill and Zhu (1996).

An analysis showing the evolution of effective wellbore radius versus injection time is provided in Figure 19, below.

Figure 19—Pressure change vs. time. The light green data points were measured while acid was being injected at the

reservoir face, resulting in matrix wormhole growth and an increase in the effective wellbore radius (rwa). The dark

blue data points were measured during the post-acid overflush, during which time wormhole length remained at a

constant 33 ft.

As shown, the effective wellbore radius grows from around 5 ft, corresponding to a skin of -2.5, at the time acid first reaches

the reservoir face to roughly 33 ft, corresponding to a skin of -4.4, at the end of the treatment. The large increase in effective

wellbore radius after fracture closure is considered strong evidence that the bulk of the stimulation benefit comes from acid

wormholes dissolved through the formation (Furui et al. 2012, Parts I and II). This type of analysis is performed for each

zone in the well to determine stimulation effectiveness and to provide skin values for initial rate forecasts and later

production evaluation.

A summary of zone permeability and acid stimulation results for the Ekofisk B-19C openhole completion are provided in the

table below:

TABLE 2–B-19C ACID STIMULATION RESULTS

Completion Interval Average Zone Maximum Effective Post Stim

Stage Zone Zone Length K*L Value Permeability Pump Rate Well Radius Skin Value

1 Zone E 199 ft 103 md-ft 0.52 md 32 bbl/min 30 ft rwa -4.34 Skin

2 Zone D 117 ft 234 md-ft 2.00 md 10 bbl/min 35 ft rwa -4.49 Skin

3 Zone C 281 ft 762 md-ft 2.71 md 37 bbl/min 30 ft rwa -4.34 Skin

4 Zone B 444 ft 848 md-ft 1.91 md 54 bbl/min 33 ft rwa -4.42 Skin

5 Zone A 404 ft 764 md-ft 1.89 md 46 bbl/min 56 ft rwa -4.95 Skin

As shown, all zones were successfully stimulated. Post-stimulation skins range from -4.34 to -4.95, corresponding to

effective wellbore radius values (rwa values) ranging from 30 to 56 ft. These openhole stimulation results are similar to

those seen in cased and perforated, fully completed wells in the field (Furui et al. 2012, Parts I and II).

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0.01 0.1 1 10

DP,

psi

Injection Time, hrs

Ekofisk B-19C Zone B Skin Evolution

rwa = rw = 0.4 f t and Skin = 0

rwa = 1.7, skin = -1.5

rwa = 5, skin = -2.5

rwa = 10, skin = -3.2

rwa = 20, skin = -3.9

rwa = 33, skin = -4.4

First Acid at Perfs

Acid Treatment Data

Overf lush

16 SPE 166209

Production Results After conclusion of acid treating operations, the B-19C well was turned over to field production operations. The well was

flowed back at increasing rates with all zones open and after approximately 3-months stabilization time, a well test was

conducted. The objectives of this test program were to check the mechanical function of the sleeves, determine any zone-to-

zone communication and acquire data on the rates and types of fluids flowing from the various completed intervals.

TABLE 3–B-19C WELL TEST RESULTS

Zone Status (O=Open, X=Closed) Oil Rate GOR Water Cut FWHP FWHT

A B C D E (STBOPD) (scf/stb) __(%)__ _(psia)_ _(oF)_

O O O O X 3580 1417 4.0 995 197

O O O O X 3564 1417 2.4 995 197

O O O O X 3395 1248 2.9 950 187

O X O O X 3409 1243 1.6 947 191

O X X O X 3439 1304 0.6 971 192

X O O O X 3347 687 1.0 941 180

O O O X X 3539 1406 0.0 1020 187

O O O O O 3119 1267 0.2 931 187

The test showed that all down-hole gauges were functioning as designed, allowing both annular and tubing pressure and

temperature from each zone to be recorded. The test program confirmed communication between the three bottommost Tor

zones: Zones A, B and C. It also indicated that one zone, Zone D, contributed more water than the others. After obtaining this

information, the water-bearing zone, Zone D, was shut-in to reduce the well’s water cut and lighten fluid column. With this

adjustment, the well now requires less gas lift gas during start-up after shut-ins. Subsequent testing has also shown that oil

production has not been significantly affected as shown in the figure below. An added benefit of shutting off the water

producing zone, Zone D, was that the well’s sulfate scaling potential was significantly reduced. This in turn means less

intervention for scale squeeze and potentially a prolonged lifespan of the well.

Figure 20—(a) Production data vs. time, annotated to show choke increases and valve operation. (b) Sulfate content

increased with water cut (WCT) approximately 175 days since start of production. Barium sulfate scaling potential

was reduced by closing the IWS valve in zone D.

The low water cut measured in the B-19C well’s early flow tests also indicated that the openhole packers had withstood the

high rate acid treatment and were effectively isolating the water zones from the acid stimulated oil zones. Review of acid

treatment data had shown some pressure/temperature communication late in the Zone C and Zone B acid treatments.

Analysis of the magnitude and duration of these leaks indicated they were small leaks; however, even a small leak while

pumping acid could provide a flow path for high pressure water during production operations. Fortunately, the well’s

production data has shown that the high pressure water zones along the horizontal section are effectively isolated.

SPE 166209 17

Figure 21—Actual producing conditions for five zones plotted over the well path and log-derived oil and water

saturation predictions.

As shown in the figure above, the differential pressures between the water zones and producing pressures in the oil zones

range from 1000 psi to 2000 psi. At these high pressure differentials, significant water production would be expected if the

openhole packers were not providing an effective seal. As a result, the small acid treatment communication seen between

zones C and B and between Zones B and A are thought to be the result of matrix communication brought on by high rate

acidizing at both ends of the inter-zone blank sections.

Overall production results from the well have been encouraging. Despite lower than expected reservoir pressures and

reservoir net pay length, the B-19C well is producing at rates above expectations. The use of an intelligent well completion

system is this well allowed the very low pressure Zone E and the marginal Zone D intervals to be completed with the better

intervals seen at the toe of the well. This would not have been possible with a conventional completion.

Conclusions An Openhole Un-Cemented Completion with a five-zone Intelligent Well System was successfully installed in the Ekofisk B-

19C well.

Acid stimulation results show that each of the five reservoir net pay intervals was effectively stimulated through the IWS

system without the rig on location.

Oil production from the well exceeds expectations despite lower than expected reservoir pressures and reservoir net pay

lengths.

Pressure communication was observed during high rate acid stimulation of the bottom three intervals. Future work will be

conducted to help characterize the nature of this pressure communication and optimize zonal isolation in future wells.

Production results show that the openhole packers placed along the horizontal section to isolate oil zones from adjacent high

pressure water zones are providing effective zonal isolation at production differential pressures in the 1,000 psi to 2,000 psi

range.

The Acid Soluble Plugs used to provide reservoir access along the un-cemented liner worked well.

Acknowledgements The authors wish to thank the ConocoPhillips management and PL018 license partners ConocoPhillips Skandinavia AS,

Total E&P Norge AS, ENI Norge AS, Statoil Petroleum AS and Petoro AS for their permission to publish this paper. Special

recognition is made to the entire B-19C team, both onshore and offshore, whose dedication and hard work resulted in a

successful well design and completion operation. The numerous service companies who worked together seamlessly in both

the design and completion phases are also recognized for their roles in the collaboration that was necessary for success.

18 SPE 166209

Nomenclature ACV=Acid Circulating Valve

Al=Aluminum

AROBM=Acid Reversible Oil Based Mud

ASP=Acid Soluble Plugs

ASV= Annular Safety Valve

BBL=Barrel

BBL/MIN=Barrels Per Minute

C=Discharge Coefficient

CFD=Computational Fluid Dynamics

DDEM=Deep Directional Electro-Magnetic

DP=Pressure Drop

ECD=Equivalent Circulating Density

F=Fahrenheit

FT=Feet of length

HCl=Hydrochloric Acid

ICV=Interval Control Valve

ID=Internal Diameter

ISIP=Instantaneous Shut-In Pressure

ISO=International Standards Organization

IWS=Intelligent Well System

LB=Pound

LCM=Loss Control Material

LWD=Logging While Drilling

MD=Measured Depth

MWD=Measurement While Drilling

OBM=Oil Based Mud

OD=Outer Diameter

OH=Open Hole

PPG=Pounds Per Gallon fluid density

PSI=Pounds Per Square Inch Pressure

rwa=Effective Wellbore Radius

SG=Specific Gravity=Fluid Density/Density of Fresh Water

STBOPD=Stock Tank Barrels Oil Per Day

TD=Total Depth

TRSSSV= Tubing Retrievable Subsurface Safety Valve

TVD=True Vertical Depth

UCS=Unconfined Compressive Strength

V0=ISO Packer Test Qualification

SPE 166209 19

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20 SPE 166209