spe-115849 pushing the limit high-rate-artificial-lift evaluation for a sour, heavy-oil, thermal eor...

November 2009 SPE Production & Operations 579

Pushing the Limit: High-Rate-Artificial-Lift Evaluation for a Sour, Heavy-Oil, Thermal

EOR Project in OmanG.H. Lanier, SPE, Petroleum Development Oman LLC; M. Mahoney, SPE, Lufkin & Partners LLC

Copyright © 2009 Society of Petroleum Engineers

This paper (SPE 115849) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Denver, 21–24 September 2008, and revised for publication. Original manuscript received for review 7 July 2008. Revised manuscript received for review 6 December 2008. Paper peer approved 20 December 2008.

SummaryPetroleum Development Oman LLC (PDO) currently operates a sour, heavy-oil (14°API) field, which has produced since 1976 from a naturally fractured carbonate reservoir located in the northern region of the Sultanate of Oman. Further field-devel-opment options have been evaluated recently, and the preferred concept will be based on thermal-assisted gas/oil gravity drainage (TAGOGD). To achieve this enhanced-oil-recovery (EOR) mecha-nism, steam will be injected into the reservoir and will eventually increase produced-fluid temperatures higher than 200°C during the projected life of the project.

A key objective for the project will involve significantly increasing the field’s ultimate recovery using high-rate oil pro-ducers capable of initially delivering a gross rate per well greater than 1000 m3/d. To achieve these well offtake rates and field ultimate-recovery objectives, highly deviated and near-horizontal well trajectories will be implemented for the planned oil produc-ers. This paper will provide a brief background of the TAGOGD recovery mechanism, anticipated reservoir conditions, and particu-lar challenges, including a summary of the evaluation of various artificial-lift technologies and the preferred method to help enable this thermal EOR project achieve the desired objectives.

IntroductionPDO has been producing oil and gas for more than 40 years. In addition to gas and light-oil fields, PDO currently operates many heavy-oil fields and continues to evaluate various types of EOR methods to improve ultimate oil recovery. A significant part of this learning effort has involved various EOR studies and pilot projects conducted over more than 20 years. As a result, EOR evaluation studies in Oman have been documented extensively (Nandyal et al. 1983; Boutkan 1987; Rice 1991; Al-Adawy and Nandyal 1991; van Wunnik and Wit 1992; Macaulay et al. 1995; Al-Shizawi et al. 1997; Al-Azkawi et al. 2002; Davy 2002; Penney et al. 2005; Penney et al. 2007; Wassing et al. 2008). There are now a variety of EOR opportunities that are evolving quickly because of the current oil-price environment and continued efforts to improve oil-recovery performance. Examples include two full-field thermal-EOR development projects that have been approved for execution in Oman. Additional pilot projects are also moving into the execution phase. Several other opportunities will follow, depending on results and further evaluation. Some projects involve more-conventional thermal-EOR methods such as steamflooding or cyclic steam stimulation (CSS), while other opportunities will likely involve less conventional approaches because of the nature of the oil reservoir.

The subject field is a naturally fractured carbonate reservoir con-taining sour, high-viscosity crude oil and located in the Ghaba salt basin in Oman. The field was discovered in 1972 and has been pro-ducing since 1976 through a process of fracture depletion and natu-ral water influx. Production is dominated by high water cut (often above 90%) because of the low matrix-oil-drainage rates and the

natural water influx through the highly conductive natural-fracture networks located across the field. Without application of any EOR technique, the field’s recovery will be low because the primary-recovery processes that displace oil from the matrix of the reservoir rock are adversely affected by the rock and fluid properties, in particular the high oil viscosity. As shown in Fig. 1, the in-situ oil viscosity is relatively high at nearly 700 cp. However, it decreases significantly with increasing temperature. Following the success of a nearby analog-field pilot, which investigated the technique of steam-assisted gas/oil gravity drainage (GOGD) and provided justification for the subsequent full-field development (Penney et al. 2007), the subject field is now being screened for feasibility using this thermal-EOR process.

TAGOGD Recovery-Mechanism ConceptGravity drainage is typically the primary recovery mechanism for low-permeability, highly fractured reservoirs (for carbonates in particular). Generally, the process relies on density differences between either gas in the fractures and oil in the matrix (GOGD) or water in the fractures and oil in the matrix [water/oil gravity drainage (WOGD)]. TAGOGD (Shahin et al. 2006) refers to the addition of heat through steam injections into the crestal location of the reservoir’s natural-fracture networks to heat the oil in the top of a matrix block by conduction. Additional steam injection continues to heat the oil deeper in the matrix block, which causes the less-viscous oil to drain downward in the matrix at an acceler-ated rate until encountering the cold, viscous oil, which acts as a barrier to flow and redirects the oil into the gas-filled fractures. Once in the fracture system, the oil will flow downward into the oil rim because of the force of gravity (Fig. 2).

Unusual for most steam projects, the oil cools as it drains vertically down the fracture into the oil rim. Given highly conduc-tive fracture networks with multidarcy effective permeability, this effect will reduce or minimally impact flow rates and support a cooler production stream for several years. However, because of the inherent reservoir heterogeneity, some wells will exhibit highly variable fluid temperatures that will eventually increase sharply across the field during the life of the project (Fig. 3).

Preliminary Oil-Producer Well ConceptsTwo basic oil-producer well concepts are proposed for the field-development plan. A deviated transitional oil-producer well type, planned to intersect the existing fracture network in the openhole completion interval, will be standardized on existing PDO thermal-well designs and will provide flexibility for managing the oil rim (Fig. 4).

A second, near-horizontal oil-producer concept, planned to inter-sect the full-field fracture network and locate the openhole comple-tion interval at the final oil-rim depth, will also be standardized on existing PDO thermal-well designs (Fig. 5). Requirement and timing for a near-horizontal oil-rim producer will likely be confirmed at least 3 years after steam injection once the final oil-rim depth has been established using the deviated transitional oil producers.

Oil-Producer Objectives and Expected ConditionsPrimary objectives for the TAGOGD-project oil producers include the following:

580 November 2009 SPE Production & Operations

• Initially deliver approximately 1000-m3/d gross rate capacity (primarily deviated transitional oil producer).

• Provide for an approximately 30-year well life following steam injection (i.e., thermally compliant).

• Enable effective oil-rim-depth management.• Deviated transitional oil producers are convertible to steam

injector or observation well for flexibility.Effective oil-rim management will be accomplished with timely

recompletion of intake depths (i.e., using wireline intervention) for the deviated transitional oil producers, which will be managed across the field to optimize recovery. Horizontal oil producers, if

Oil, gas, and waterSTEAM

OOWC

Fracture GOCOil RimFracture OWC

Aquifer

STEAM

Oil rim

Aquifer

Fig. 2—Subsurface TAGOGD development concept for the subject field.

1

10

100

1000

326 346 366 386 406 426 446 466 486 506 526

Temperature (K)

Visc

osity

(cp)

visc (B)

visc (A)

Fig. 1—Measured-oil-viscosity data from different samples for the subject field.

Table Name: P4_ESC_STEAMCONTROLTSS1Plot Name: P4TplotTime=2029.991 [YEAR]

Tem

p (K

)

5.5e+02

5.0e+02

4.5e+02

4.0e+02

3.5e+02

3.0e+02

Time (year)2015.0 2017.5 2020.0 2022.5 2025.0 2027.5 2030.0

P4_ESC_STEAMCONTROLTSS1 TempP4_NC_STEAMCONTROLTSS1 TempP4_NESC_STEAMCONTROLTSS1 TempP4_SC_STEAMCONTROLTSS1 TempP4_SWSC_STEAMCONTROLTSS1 TempP4_WC_STEAMCONTROLTSS1 Temp

P4_E2SC_STEAMCONTROLTSS1 TempP4_NE2SC_STEAMCONTROLTSS1 TempP4_NSC_STEAMCONTROLTSS1 TempP4_SEC_STEAMCONTROLTSS1 TempP4_WSC_STEAMCONTROLTSS1 Temp

Fig. 3—Oil-producer predicted produced-fluid-temperature profiles for the subject field.


required, will be designed so the horizontal openhole completion is located at the desired final oil-rim depth and will therefore not require recompletion. As a result, timing of recompletions will be scheduled to coincide with expected well-servicing activi-ties to reduce costs. Otherwise, well-intervention timing will be variable and affected by rising fluid temperatures, steam, or gas breakthrough.

Expected conditions and fluids for the TAGOGD project are as follows:

• An operating average reservoir bottomhole pressure (BHP) range of 4600 (current) to 3000 kPa

• A highly variable produced-fluid bottomhole-temperature (BHT) range of 53 to +200°C (Fig. 3)

• A nearly constant well tubinghead pressure (THP) at approxi-mately 1500 kPa (with casing vapor-recovery system if required)

• An initial gas/oil ratio (GOR) at approximately 10 m3/m3• A potential for high basic sediments and water (BS&W%)

likely approaching 100% initially• An initial H2S and CO2 content of < 0.3 mol% and < 3.0

mol%, respectively• An average reservoir matrix permeability of < 20 md• An effective natural-fracture-permeability range of 5 to 50

darcies• An oil gravity of 14°API• An oil viscosity of < 700 cp at current reservoir conditions

(Fig. 1).

Deviated (~45°) transitional oil-rim producer

KPM mud

13⅜ in., 54.5#, K55, BTC csg

9⅝ in., 40# K55 NK3SB csg

8.5-in. openhole completion

Shuaiba

Hawar/Kharaib

N. Umr

Natih

Uer

Fars

5½ in., 17#, J55, BTC tbg, 5¾-in. pump

Thermal pkr w/4½-in. tailpipe and SSDs

Approx. BHP range:

4600 to 3000 kPaProduced fluids BHT range: 53 to +200°C

TD ~25 m below OWC

Possible intake depth recompletion targets

390 – 395 mSS405 – 410420 – 425435 – 440 (horizontal wells)

Fig. 4—Proposed deviated transitional oil-rim producer well concept for the subject field.

Near-horizontal oil-rim producer

Shuaiba

Hawar/Kharaib

N. Umr

Natih

Uer

Fars

Approx.BHP range:

4600 to 3000 kPa

Produced fluids BHT range: 53 to +200°C

KPM mudKPM mud

13⅜ in., 54.5#, K55, BTC csg

9⅝ in., 40# K55 NK3SB csg

8.5-in. openhole completion (< 1000 mah)

5½ in., 17#, J55, BTC tbg, 5¾-in. pump set at < 80 deg

TD ~ 427 – 447 mSS

Fig. 5—Proposed near-horizontal oil-producer well concept for the subject field.


Target operating pressure is currently assumed to be as low as 3000 kPa. However, this is subject to further optimization, which may likely identify opportunity or external constraints, such as with a nearby-field-thermal-EOR project that increased the target operating pressure to approximately 3800 kPa to help reduce water-disposal requirements. These considerations will be re-evaluated and will likely result in a change to the target operating pres-sure—higher or approaching 4000 kPa. Similarly, expected facility backpressure observed at the oil producers is currently assumed to be approximately 1500 kPa (to mitigate steam flashing). Formation-water production will likely initially increase or approach 100% BS&W, depending on well off-take rates until matrix-oil-drainage rates increase in response to steam injection, though this may also be affected by aquifer pump-off wells that may be employed to help manage the oil-rim depth or reservoir operating pressure.

Artificial-Lift Functional RequirementsThe primary functional requirement for the preferred artificial-lift method is the ability to initially deliver a gross-rate capacity of approximately 1000 m3/d over a range of reservoir operating pressures. Delivery of the desired gross-rate capacity per well will improve the project’s economics by decreasing the required well capital-expenditure (CAPEX) budget or well quantity necessary to deliver the simulated production forecast over the project life.

Deviated and horizontal oil-producer wells are required to man-age the oil rim effectively. Therefore, the preferred system must be configured for easy installation—likely at a deviated hole angle to achieve desired rate capacity and recovery.

Artificial-lift-system flexibility and robustness to cater to a highly variable produced-fluid temperature across the field dur-ing the 30-year project life are critical requirements. Preliminary forecasts indicate this will likely be the case because of the hetero-geneous nature of the target-reservoir natural-fracture network.

Expected BS&W% will be highly variable over the project life and will approach 100% during some project phases because of varying quantities of condensed steam and/or formation water produced by the reservoir natural-fracture network. In addition, preliminary reservoir-simulation forecasts suggest initial BS&W% may remain above 50 to 60%, or even approach 100% (at least until sufficient matrix-oil-drainage rates can be established follow-ing steam injection). A preferred artificial-lift system must cater to this variability.

The field’s produced oil is considered heavy oil, with GOR at approximately 10 m3/m3 and average “cold-phase” oil viscosity approaching nearly 700 cp. However, oil viscosity will decrease substantially with increasing temperature to less than 5 cp when above 200°C. A preferred artificial-lift system must cater to this variability.

Corrosive fluids (i.e., < 0.3 mol% and < 3.0 mol% H2S and CO2, respectively) and high formation-water salinity (i.e., chlorides > 100000 mg/L) are likely, if not certain initially. Therefore, the artificial-lift-system ratings must satisfy this minimal requirement. By injecting steam at or nearly at 250°C into the reservoir, it is expected that H2S and CO2 produced-fluid content will eventually increase by some unknown rate to a higher fluid-content amount, possibly as high as approximately 3.0 mol% and 8.0 mol%, respectively, depending on nearby analog-field studies. As such, the system must ultimately be designed, or be easily upgraded to, address this uncertainty.

To facilitate timely data gathering to support an effective reservoir-surveillance strategy, the system must be configured or integrated with project-surveillance requirements.

In addition, the preferred system must be cost-effective in terms of taking into account the expected life cycle of CAPEX and operating-expenditure (OPEX) budget requirements, but it also will be sufficiently flexible to cater to uncertainties related to individual-well offtake requirements.

Finally, because of the significant potential impact to produc-tion and health, safety, and environment (HSE) requirements, the preferred system must be a “proven” technology with existing field-installation history and a database sufficient to provide a high

degree of assurance for expected performance reliability, as well as PDO well-integrity and operating-safety standards.

Artificial-Lift Strategy and EvaluationIn summary, the artificial-lift strategy for the subject-field TAGOGD project can be outlined as follows:

• Use of industry “proven” technology• Flexibility for use of emerging technology during project life• Use of low-cost, technically acceptable solution• A vendor prequalification system conducted before project

approval to access local-market capability and to confirm budget cost estimates

As noted, the proposed strategy will focus on consideration of proven technology, given the potential impact to the project. Because the TAGOGD project will execute only after startup of a nearby full-field steam project, time is a luxary that will allow serious consideration of new technology developments. There-fore, flexibility to consider these options is also an underlying part of the proposed strategy. One such example is the evolving progress of the “high-temperature” electrical-submersible-pump (ESP) technology, which is showing progress and is growing in many Canadian heavy-oil field developments through experience. Extended run-life data are still somewhat limited to date.

Several artificial-lift options were considered in the evaluation and included the following:

• Gas lift• ESP• Progressing-cavity pump (PCP)• Jet-pump• Long-stroke rod pump• Conventional beam pumpEach particular artificial-lift option has specific advantages and

disadvantages, depending on the application and downhole-reser-voir-fluid conditions, which are often changing over the project life. Because of the complexity of changing conditions and various technical and/or operational considerations, an accepted practice for artificial-lift evaluation involves using a matrix of ranking table of criteria to compare and contrast the different choices in the context of a particular field application using established objective and subjective measures. Although there are other considerations, Fig. 6 illustrates an example of some of the key criteria considered in the artificial-lift selection process for the TAGOGD project and the preferred option. Symbol “H” indicates a high or attractive rating, while “L” indicates a low or unattractive rating.

In most cases, a matrix of ranking criteria helps identify or bring additional focus to key technical or operational issues that may influence the final selection. More extensive ranking matrix examples and other recommendations to help with artificial-lift selection are widely available and were referenced in this evalu-ation (Neely et al. 1981; Brown 1982; Clegg 1988; Clegg et al. 1993). To identify the ideal or preferred options, ranking criteria also include consideration of local PDO operating experience and strategies, evolving industry experience or best practices, and new technology developments.

Gas Lift Option. Gas lift offers particular advantages related to high-GOR oilwell applications and offers easy surveillance access, in addition to operating fl exibility for changing conditions. However, for the subject TAGOGD-project circumstances, gas lift is expected to be a very expensive option, with signifi cant initial CAPEX requirements. A technical disadvantage is the maximum-temperature limitation for average produced fl uids imposed at the wellhead because of practical limits on the size of cooling fans required to satisfy expected maximum inlet gas-temperature rat-ings for the compressor. Other likely issues or disadvantages of gas lift for the TAGOGD project include:

• Arrangements for a convenient, inexpensive gas supply• Additional gas-flaring requirements• Full-field-shutdown production deferment• Reduced lift performance with decreasing BHP and increas-

ing BS&W%


• Required high-temperature, expensive gas lift equipment accessories

ESP Option. ESP systems offer signifi cant advantages for most high-rate applications, provided that reliable run-life performance can be delivered over the range of expected conditions during the project life. However, the conventional ESP option is not currently recommended for the planned deviated transitional oil producers for the following reasons:

• Intake-depth recompletion requirements (restricted access)• Operating-temperature limitations• Gas-handling limitations• High CAPEX and OPEX (relative to other options)• Limited field-operating experience in thermal applications

to date• Poor pump efficiency or emulsion tendencies at initial condi-

tions, or at low operating temperaturesDespite these issues (particularly during the “cold” project

phase), evolving “high-temperature” ESP technology (Solanki 2005; Gaviria 2007) may offer distinct advantages for horizontal oil producers where surveillance intervention activities are not likely planned and produced-oil viscosity (or emulsion tendency) will likely be greatly reduced during the “hot” project phase. These advantages include the opportunity to further increase gross-rate capacity and reduce well costs with smaller casing and/or tub-ing. However, further review will be necessary in due course. An opportunity to pursue high-temperature ESP technology will also depend on the TAGOGD project’s performance, as well as its rate of progress and the results of the fast-growing installation database of performance-reliability statistics. Although the current industry technology leader has a clear advantage of nearly 300 installa-tions and a record run-life performance at more than 3 years as of July 2008 (as reported on its website), other competitors (Tetzlaff et al. 2007) are already quickly developing their own versions of a high-temperature ESP for heavy-oil thermal-EOR projects. And despite the limited installation experience to date, competition will no doubt increase the quantity of field installations and will very likely increase the industry’s learning rate. This will presumably lead to more-rapid performance and reliability improvements.

PCP Option. PCP systems are ideal for lower gross-rate (i.e., < 600 m3/d) well applications operating at shallow depths, or where signifi cant solids may be coproduced. Traditional PCP systems are “rod-driven” by surface motors. However, less-conventional systems are available that combine features of both PCP and ESP systems and are powered from “bottom-drive” motors (Ramos

et al. 2007). For both Canadian (Dusseault and El-Sayed 2000) and Venezuelan (Blann et al. 1999) heavy-oil fi eld developments, PCP artifi cial lift is a popular choice, though mostly for cold heavy-oil production systems (CHOPS). Sand-coproduction capacity is often considered a technical advantage for adopting the PCP method. In addition, PCP systems are often attractive because of relatively low CAPEX and OPEX requirements. However, run-life performance can also be a challenge depending on operator experience and fi eld-specifi c circumstances. Still, for the subject-TAGOGD-project requirements, it is not technically possible for PCP technology to deliver production capacity approaching the desired gross-rate capacity.

Significant PCP-technology-development progress and success have been noted to date (Beauquin et al. 2005; Beauquin et al. 2007) in the area of high-temperature or metal/metal PCP systems for thermal heavy-oil applications. PDO is considering a field trial of this technology on a different project that will involve lower pro-duction-rate requirements. However, the metal/metal PCP is also unattractive for the subject-TAGOGD-project conditions because of current design-rate limitations.

Jet-Pump Option. Though used in many different application circumstances (De Ghetto and Giunta 1994; Anderson et al. 2005; Chen et al. 2007) and quite advantageous for deep wells, jet-pump systems are usually considered only after evaluating other conventional approaches or as a last resort for many artifi cial-lift applications. Jet-pumping technology is often used in drilling or stimulation applications and can provide a fl exible option for well testing scenarios depending on circumstances. Key advantages for artifi cial-lift applications include high rate capacity and ease of access for intervention or for system retrieval for both deviated and deep wells. However, jet pumping is not recommended for the subject TAGOGD project for the following reasons:

• Large, local centralized facility requirements• High CAPEX (surface, treating and high-pressure pump

equipment)• Potential for high OPEX (generally higher than beam pump)• Reduced lift efficiency and performance sensitivity to chang-

ing produced-fluid characteristics• High emulsion risk (requiring large vessels, demulsifier

chemicals, and other factors)• Ideal power fluid (high-API-gravity oil) not conveniently

available over the life of the project• Challenging surveillance requirements• Increased HSE exposure (high-pressure flowlines)• Limited PDO production-operations experience to date

Jet Pum

Beam

< 15 API or > 500 cp(<60°C)

PumJet

PumTemperature

Heavy Oil

L M/L

Pum Pum

scf/STB)

Heavy OilHeavy OilHeavy Oil

Pum Pump

90-350 v/v (500 to 2000

PumPump< 120°C (250°F)120-175°C (250-350°F)> 175°C (350°F)

Reservoir Access For surveillance and production optimization

Maintenance Interventions

Change-outs / run-life

LowHHHHMhgiH

< 160 m3/d (1000 b/d)160-1600 m3/d (1000-10k p/d)

CAPE HH H HOPEX

< 90 v/v (< 500 scf/STB)

HHH H

MM

M

H M

M

H

H H H H H

HMM

M

MH HMMM

MLH H H

HH

H

H

H H H H

H H

H

H H H

Gas/Oil Ratio

Water Cut

Production Rate

MM/L M/L

M/L M/L

H/M H/MH/M

H H HM/L M/L

Fig. 6—Artificial-lift ranking matrix with criteria for the subject TAGOGD project.


Long-Stroke Rod-Pump Option. Long-stroke-pumping systems have been available in the industry for many years. However, improved or modern versions now designed with up to 365-in. stroke length with reciprocating composite-fi ber belts have been in use globally for more than 10 years, particularly for heavy-oil fi eld developments in Canada (Zatka 1999), as well as Venezuela and China. Advantages are mostly related to energy effi ciency (Antoniolli and Stocco 2007) and the long-stroke capacity, which enables high-rate production at reduced unit cycle speed. It also improves pumping effi ciencies (McCoy et al. 2001; McCoy et al. 2003), especially for deeper or high-load wells (McCannell and Holden 2001). However, this method is not recommended for the subject TAGOGD project primarily because of the current design limits on gross-rate capacity. In addition, PDO has limited operating experience with this type of lift and has yet to establish a reliable well-servicing capability for this unique equipment con-fi guration. Field trials are now being reconsidered to reduce OPEX for lower-gross-rate applications.

The Schoonebeek thermal-EOR project (Jelgersma 2007) in The Netherlands is proceeding with the long-stroke system as the preferred artificial-lift choice for the project’s horizontal thermal oil producers, which are designed to deliver at least an average of 400 m3/d of gross-rate capacity per well while targeting a depleted oil reservoir at approximately 800 m true vertical depth.

Preferred Artificial-Lift MethodIn summary, the conventional beam pump offers several advan-tages and is currently considered the preferred artificial-lift method for the subject TAGOGD project. Conventional beam pumping is the most proven and most used artificial-lift approach for heavy-oil thermal projects worldwide, despite the emergence of various alternatives. Particularly when compared to other unit geometries using conventional rod-string design (Byrd 1968; Ghareeb et al. 2007) and for ideal conditions (such as vertical well, and shallow depths), the technical limit gross-rate capacity for a conventional beam-pump geometry has been calculated to approach or exceed

1000 m3/d gross-rate capacity, depending on pump depth (Fig.7). Studies confirm that high-rate lift is possible with conventional beam-pumping using modern equipment and operating practices. Compared to a Reverse-Mark or Mark-II geometry, a conventional beam-pump unit is generally recommended for shallow depths (i.e., approximately < 2,000 ft). Finally, over a range of BS&W% from 0 to 100%, gross-rate capacity is calculated to change less than approximately 2% for the assumed depths and fluid types.

For the subject TAGOGD project’s expected conditions, more-detailed technical analysis was required to explore the well-devia-tion impact on gross-rate capacity and other changing conditions expected over the project life. Results confirmed that the conven-tional beam-pump system, combined with an improved rod-string design configuration using sinker bars and a continuous rod [a common industry best-practice for rod-pumping in highly deviated wells (Purdy and Bacon 2004; Hein et al. 2008)], yielded gross-rate capacity performance approaching or greater than 1000 m3/d for many scenarios—largely because of the subject-field circumstances or shallow depth and high reservoir operating pressure, as well as the large casing and tubing sizes planned for the oil producers. Other attractive system features include a high-temperature rating, significantly lower CAPEX/OPEX budget requirements (when compared to either gas lift or ESP options), and flexibility for pos-sible changes in well offtake requirements during the project life.

Although not detailed in this paper, a project life-cycle review of the beam-pump system estimated CAPEX/OPEX impact to the subject TAGOGD project reflected a substantial economic advan-tage relative to other options. In addition, PDO operating experi-ence with the conventional beam-pump system is quite extensive, highlighted by the fact that more than 30% of oil production and more than 40% of currently operating wells rely on this method.

Key limitations for this system are mostly related to increasing depth (i.e., pump depths > 1500 m), increasing rod and tubing wear in deviated wells, and poorer pump efficiency if free-gas produc-tion is excessive. However, increasing depth will not be a concern for the subject field, given that the target reservoir does not vary

producing water cut 50 %water Spgr =1.05oil API gravity=40well head pressure=150 psivertical well

pump intake pressure= 200 psi

CONV UnitsRM UnitsMII UnitsAvarge rate


pump intake pressure= 200 psi

Production vs. depth for different pumping geometries Mark II, reverse mark and conventional units

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

15000 14000 12000 10000 8000 6000 4000 3000 2000 1000Depth (ft)

Prod

uctio

n (B

PD)


pump intake pressure= 200 psiproducing water cut 50 %water Spgr =1.05oil API gravity=40well head pressure=150 psivertical well

Producing water cut 50%Water Spgr = 1.05Oil API gravity = 40Well head pressure = 150 psiVertical well

Pump intake pressure = 200 psi



CONV unitsRM unitsMII unitsAvarge rate

Fig. 7—Beam-pump-system gross-rate capacity for unit geometry vs. depth (Ghareeb, MEALF, 2007).


significantly across the field. Rod- and tubing-wear risk will be greatly reduced or mitigated by well-trajectory optimization, which will be addressed further in the detailed design phase along with other mitigation measures. Common industry practices (e.g., use of gas anchors, casing vapor-recovery system) will be employed to enhance downhole-pump efficiency (Rowlan et al. 2007), though simulated production forecasts for GOR do not suggest that this will be a significant risk over the project life. Well- and reservoir-management strategy, as well as production optimization, can be enhanced with sophisticated beam-pump surface control or automa-tion technology (Sanchez et al. 2007; Palka and Czyz 2009) readily available. PDO is currently pursuing field trials with various suppli-ers of this technology. Evolving industry best practices, to comple-ment PDO’s local knowledge, are also well documented (Rowlan et al. 2007) and will be used to improve performance further. Finally, it will be possible to minimize well-intervention costs, particularly for the deviated transitional oil producers, by integrating WRM surveillance activities with planned well-servicing activities.

Design Method and Supporting Software Analyses ResultsDesign Approach. For the subject-TAGOGD-project oil produc-ers, the beam-pump-system design approach was iterative and involved several key tasks:

• Confirming well types (i.e., deviated transitional vs. hori-zontal)

• Confirming initial build rates (degrees/30m) and kickoff-point (KOP) depth constraints

• Generating proposed well-deviation plans on the basis of esti-mated target-reservoir top and final oil-rim depth requirements

• Consulting industry expertise for beam-pump and rod-string “conservative” limit criteria to extend tubing run life

• Using industry software to analyze beam-pump-system parameters with proposed well-deviation plans to determine sys-tem constraints and equipment requirements

• Estimating achievable gross-rate capacity for range of pump-intake depths, pressures, efficiency, and other factors

Key System Parameters and Constraints. Fig. 8 presents a schematic of the adopted beam-pump-system design approach

highlighting several key parameters and constraints considered during the process. Important to the design process is use of a rod-pump-system design software tool with features that support sophisticated analysis of rod pumping in highly deviated wells. This software tool was used for all of the subject-fi eld-oil pro-ducer-scenario results. Validation of software predictions has been conducted previously, with results confi rming that the default fric-tion and pump factors are generally conservative (i.e., they slightly overpredict peak polished-rod loads and underpredict minimum polished-rod loads).

Well-trajectory planning is critical for beam-pump-system design in highly deviated wells (Xu et al. 2006; Hein et al. 2008). The impact of well deviation on predicted rod side loads signifi-cantly increases with approximately 2 degrees/10 m build rates. As a result, incorporating changes in azimuth combined with turns in the build section of a well trajectory can be extremely detrimental to the expected beam-pump performance for the entire well life.

Other key parameters that can also positively influence beam-pump-system performance include larger casing and tubing size, which allows larger rods, larger pumps, and more space for natural fluid separation to enhance pumping efficiency.

System Design Process and Key Limit Criteria. For simplic-ity and “fi rst-pass” planning purposes, well-trajectory criteria were based on the following assumptions, which are considered acceptable for drilling circumstances expected in the subject-fi eld oil producers:

• Constant build rate of < 5 degrees/30 m• No turns, constant azimuth• KOP depth below expected 13 3⁄8-in.-casing-shoe depth (i.e.,

top of Natih)Relying on extensive industry expertise and consulting with

other-operator artificial-lift expertise, the following rod-string cri-teria and preferences were used during the design process to extend tubing run life:

• Maximum axial loads < 80% rating• Maximum side load < 3000 N• Maximum drag load < 1500 N• Maximum buckling load < 950 N• Minimal length of rod buckling above pump

Beam-Pump Design Approach

Parameters and Constraints

KPM mud

Stuffing box temperature limits

Optimise/reduce rod drag, side, buckling loads

Rod-fall during downstroke-limits pumping speed

Tubing rotation (improve wear life)

Well trajectory criteria :> max BURs <5 deg/30m> variable BUR w/ depth> no turns, constant azimuth

Rod-string configuration :> CoRoD – higher strength, more uniform load distribution> sinker bar for increased stiffness

Pumping Unit: strength & speed Reduce casing pressure –vapor recovery system

Pump located in deviated hole near reservoir :> maximize fluid-level above pump> reduced gas interference

Maximize casing size :> larger tbg> larger rods> larger pump> natural separation

KPM mud

Stuffing box temperature limits

Optimize/reduce rod drag, side, buckling loads

Rod-fall during downstroke-limits pumping speed

Tubing rotation (improve wear life)

Well trajectory criteria:> max BURs <5°/30 m> variable BUR w/depth> no turns, constant azimuth

Rod-string configuration:> CoRoD – higher strength, more uniform load distribution> sinker bar for increased stiffness

Pumping Unit: strength and speed Reduce casing pressure –vapor recovery system

Pump located in deviated hole near reservoir:> maximize fluid-level above pump> reduced gas interference

Maximize casing size:> larger tbg> larger rods> larger pump> natural separation

Fig. 8—Beam-pump-system design approach: key parameters and constraints considered.


Additional accepted industry criteria to support a reliable, full-life beam-pump-unit performance expectation included:

• Maximum structure and gear-reducer load < 100% rating• Maximum SPM < 10 (i.e., minimum polished-rod load >

4450 N)

Data Input, Assumptions, and Scenarios. After some initial design iterations to explore equipment specifi cations required to deliver the desired gross-rate capacity, the following data input, assumptions, and scenarios illustrated in Fig. 9 were modeled using a software tool to generate a range of beam-pump-system performance predictions:

• Well types: deviated transitional and horizontal (Figs. 4 and 5)• Tubing size: 5 1/2 in.• Pump size: 5 3/4 in.• Rod string: 2-in. sinker bar with 1-in. continuous rod• Fluid: 100% formation water at 1.16 SG• Unit type/sizes: C1824-305-240 and C1824-365-216• Sensitivities: pump setting-depth range: 311 to 410 m subsea.

Hole deviation range: 40 to 70 degrees. Pump-intake-pressure (PIP) range: 4000 to 1500 kPa. Pump efficiency range: 100 to 90%

Predicted Beam-Pump-System Performance Results. A range of potential scenarios for the subject-fi eld conditions was considered to generate a range of beam-pump-system performance-prediction results as listed in Figs. 10 and 11 and illustrated further in Fig. 12.

DiscussionAfter some initial preliminary design iterations, prediction results confirmed that a C1824 unit would be required for this application. To support the project oil-producer gross-rate objectives, 4 1/2-in. and smaller tubing sizes were mostly inadequate. All subsequent sensitivity analyses assumed a 5 1/2-in. tubing size. Similarly, smaller insert pumps, which offer well-servicing advantages by reducing the need to pull tubing, are also unlikely to support the objectives. A 5 3/4-in. tubing pump was identified as a viable, minimum size option. Various combinations of conventional sucker rods were also considered. However, predicted rod loads were high and were expected to impact beam-pump system performance negatively. Therefore, an industry practice for highly deviated

wells involving use of sinker bars (shallow or near-vertical well section) combined with continuous rod was adopted to improve expected performance. Sinker bars provide additional weight to increase minimum polished-rod loads and stiffness to reduce rod-string buckling tendencies. Continuous rod, which is quickly grow-ing for use in both PCP and beam-pump systems (Wiltse and Veir 1995; Blann et al. 1999; Zatka 1999; Purdy and Bacon 2004; Ariza et al. 2006; Hein et al. 2008), offers several advantages includ-ing enhanced tubing and rod run life because of reduced wear or reduced load-bearing (more-uniform) contact, lighter weight for a given depth, minimal coupling connections, and reduced flow restriction. However, as noted in Fig. 11, rod-buckling loads still present a challenge for further beam-pump-system optimization.

As noted previously, a simple or constant-build rate criterion limited to less than 5 degrees/30 m was used as a basis for the well-deviation plans for both oil-producer well types. As shown in Fig. 12, achievable gross-rate capacity for the beam-pump system is reduced in the horizontal oil producer (relative to the deviated transitional) because of the higher hole angle or increased rod side, drag, and buckling loads, but also because of the slightly deeper pump depth assumed. Although lower pump intake pressures and deeper (i.e., higher hole angle) pump depth locations suggest a significant reduction in gross-rate capacity, these are more-extreme scenarios (i.e., < 3000 kPa PIP) and are less likely for the proposed TAGOGD subsurface field-development concept. Because of the likely high target-reservoir operating pressure (i.e., approximately 4000 kPa), it will be possible to locate the downhole pump shal-lower (i.e., lower hole deviation), which will improve system performance. 100% BS&W was assumed in all sensitivities, but expected BS&W% will likely be more than 60 to 70% for most of the project life. Therefore, beam-pump-system performance will also improve accordingly.

Further optimization of the preliminary proposed beam-pump-system design is planned during the detailed design project stage. Opportunities to explore further include:

• Well-trajectory optimization employing a variable build rate (i.e., catenary design)

• Detailed beam pump design options (e.g., unit upgrades, shallow pump depth, rod-string configuration)

• Design optimization (e.g., operating parameters, limit criteria)

Well Trajectory Optimization for AL

0

100

200

300

400

500

600

0 200 400 600 800 1000 1200 1400

Vertical Section (m)

TVD

BD

F (m

)Deviated (45°)Transitional oil rim producer(370 mSS Shuaiba top)Horizontal oil rim producer(427 mSS)

~430 m pump depth (40°, 411 m TVD)




Deviation criteria:> BURs < 5°/30 m> constant azimuth, no turns> KOP depth below 133/8-in. csg (~200m TVD BDF)

Fig. 9—Beam-pump-system scenarios for pump depth and hole inclination for oil-producer well types.


ConclusionsSeveral key conclusions are evident for the expected TAGOGD project oil-producer conditions on the basis of preliminary design iterations and the prediction results for the conventional beam-pump system:• A conventional beam-pump system is currently the preferred

artificial-lift method.• Initial technically achievable gross-rate capacity range is attrac-

tive over a range of conditions at approximately +1000 m3/d (deviated transitional oil producer) and +600 m3/d (horizontal oil producer).

• Gross-rate capacity range is largely improved by casing/tubing size, shallow reservoir depth, and high reservoir pressure.

• Gross-rate capacity range is reduced by increasing hole angle, increasing pump depth, and decreasing pump-intake pressure.

• Rod-string buckling limitations are a key beam-pump-system constraint that can be mitigated by well-trajectory optimization.

• High-temperature ESP technology may be an attractive alterna-tive for the near-horizontal oil producer.

AcknowledgmentsThe authors acknowledge the Ministry of Oil and Gas in the Sul-tanate of Oman for permission to publish this paper and PDO for use of the data and their support on the project. The authors also acknowledge the many contributions from PDO, Shell, and Lufkin staff related to this project.

ekatnI pmuPeloH lleWType Angle Pressure 100% eff. 90% eff.

mAH BDF mTVD GL (deg) (kPa) (Sm3/d) (Sm3/d)

45° TW 470 445 42 4000 1137 10233000 1137 10232800 801 7212500 723 6512000 616 5541500 409 368

450 422 39 4000 1214 10933000 1139 10252000 881 7931500 576 518

Horizontal 600 510 68 4000 582 4663000 393 3142000 344 275

500 460 51 3500 714 571

430 411 40 3500 791 6333000 783 626

Pump DepthGross Rate

Fig. 10—Gross-rate performance predictions.

daoL xaMtinU Average Gear Reducer Rod Load Max Max MaxType/Size Max Load Min Load % Rating Pump Speed % Rating @ 0.9 Buckling Load Side Load Drag Load

(N) (N) (%) (SPM) (%) (%) (N) (N/rod) (N/rod)

C1824-365-216 119142 9857 73 8.5 72 30 / 58 879 1605 321C1824-365-216 119142 9857 73 8.5 72 30 / 58 879 1605 321C1824-305-240 126205 13114 93 5.6 80 32 / 65 878 1768 354C1824-305-240 129063 13139 95 5.1 79 32 / 67 878 1831 366C1824-305-240 134457 14330 99 4.3 82 34 / 71 877 1941 388C1824-305-240 134806 17848 99 2.9 79 33 / 71 877 1969 394

C1824-365-216 117658 8368 72 9.1 73 30 / 57 876 1559 312C1824-365-216 113550 9164 70 8.5 71 29 / 55 876 1508 302C1824-365-216 145349 9419 90 6.8 87 38 / 77 876 2088 418C1824-365-216 140116 14402 86 4.5 80 35 / 74 876 2032 406

C1824-365-216 132341 22509 81 4.5 76 31 / 65 879 2237 447C1824-365-216 109373 20672 67 4.5 61 25 / 51 878 1729 346C1824-365-216 123343 21129 76 4 67 29 / 59 878 2001 400

C1824-365-216 137791 18402 85 5.4 82 34 / 68 877 2327 465

C1824-365-216 147929 13950 91 6 89 38 / 74 875 2520 504C1824-365-216 156604 14064 97 5.9 94 40 / 80 875 2705 541

Unit

Fig. 11—Predicted results for beam-pump-system operating parameters.


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Fig. 12—Predicted gross-rate performance sensitivities.

0

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1400

0 1000 2000 3000 4000 5000

100% Pump Efficiency90% Pump Efficiency

Deviated-TransitionalHorizontal

450m pump depth,

39 deg hole angle

470m pump depth,

42 deg hole angle

600m pump depth, 68 deg hole angle

430 & 500m pump depth, 40 & 51 deg hole angle

0

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1200

1400

0 1000 2000 3000 4000 5000

100% Pump Efficiency90% Pump Efficiency

Deviated-TransitionalHorizontal

Predicted Performance

0

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1400

0 1000 2000 3000 4000 5000

Pump Intake Pressure (kPa)

Gro

ss R

ate

(Sm

3 /d)

100% pump efficiency90% pump efficiency

Deviated-TransitionalHorizontalDeviated-transitionalHorizontal

450 m pump depth,

39° hole angle

470 m pump depth,

42° hole angle

600 m pump depth, 68° hole angle

430 and 500 m pump depth, 40 and 51° hole angle


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Gary Lanier is on temporary assignment with Petroleum Development Oman LLC as production technology discipline leader with primary focus in EOR studies. He has more than 20 years of E&P experience in newfield and brownfield devel-opments onshore USA and offshore GoM, as well as the Middle-East, southeast Asia, and Australia. He holds a BSc degree in mechanical engineering from The University of Texas at Austin, MSc engineering degree from Stanford University and MBA degree from the University of Houston. He is an active SPE member and is also a registered PE in petroleum engineer-ing in the State of Texas. Mark W. Mahoney is the senior artifi-cial lift projects manager for Lufkin Industries Oil Field division. Mahoney has more than 30 years experience with rod-pump-ing operations globally and is currently based in the Sultanate of Oman. His areas of research focus include improvements in rod pumping equipment, systems, and applications. Mahoney is a peer review editor for SPE on the Productions & Operations Journal and a steering committee member for the SPE IOR/EOR conference in Muscat Oman (biannual). He has worked on SPE workshops in India and Cairo.

spe-115849 pushing the limit high-rate-artificial-lift evaluation for a sour, heavy-oil, thermal eor...

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