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Gas lift
This article, written by Dennis Denney, contains highlights of paper IPTC 17091, ’Extending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work,’ by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure. Through-tubing well work was used because it is more economical than a full workover, particularly for wells in a mature field with depleted reserves. Enhanced and optimized cement slurry was engineered with a well-work approach that specified acoustic fluid-level monitoring. The packer leak was repaired successfully. Introduction This oil and gas field is 260 km from Kerteh, Malaysia. Discovered in 1971, first oil production was in 1978. The field is in the southeastern part of the Malay basin at an average water depth of 70 m. The field contains both gas and oil reservoirs. In August 2002, communication was observed between the production casing and tubing of the subject well, indicating a leaking production packer. Four major attempts to correct the problem were conducted, all unsuccessful. The first attempt was in February 2003 by bullheading calcium carbonate (CaCO3) into the annulus. This procedure was attempted again in May 2003. In August 2007, a coiled-tubing (CT) unit was used to spot cement inside the production tubing and displace it into the annulus through a gas lift mandrel to the top of the packer. Another cementing job was attempted in December 2008, through the same gas lift mandrel. Diagnosis Lessons learned from the first cementing failure, in 2007, were used to design the attempt in 2008. Even though job execution was smooth in the field, several mistakes occurred that were not realized by the team during the job-design process. The experiences of those cementing attempts helped mature the subsequent design and decisions, ensuring success for future packer-cementing jobs in peninsular Malaysia operations. Cement-Slurry Design. CT-cementing procedures are different from those of conventional/primary cementing from a rig, with the biggest difference being the need for batch mixing for CT cementing vs. on-the-fly mixing for primary cementing. Batch mixing requires higher mixing energy compared with primary cementing, with an additional mixing energy to pump the cement slurry through the CT relative to pumping down the casing. The higher mixing energy decreases thickening time (TT) such that the cement slurry has potential to accidentally set inside the CT, thereby requiring a suitable retarder to prolong the TT.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146652, ’Offshore ESP-Selection Criteria: An Industry Study,’ by Michael C. Romer, SPE, Mark E. Johnson, SPE, Pat C. Underwood, SPE, and Amanda L. Albers, SPE, ExxonMobil, and Russ M. Bacon, R.M. Bacon Engineering, prepared for the 2012 SPE Deepwater Drilling and Completions Conference, Galveston, Texas, 20-21 June. The paper has not been peer reviewed. Most offshore wells that require artificial lift are gas lifted because gas typically is readily available and, compared with other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electrical submersible pumps (ESPs) can increase oil production and reserves recovery efficiently and economically under the appropriate operating conditions. ESPs can lower the abandonment pressure and, in the long term, possibly reduce the total number of wells required to deplete an asset. Because few ESPs are installed in offshore wells, ESP-screening “rules of thumb” were formed as a simple guide to prioritize offshore ESP candidates. Introduction Pumps typically achieve higher drawdowns than gas lift under appropriate operating conditions. Early in the life of the pump, greater production is achieved with its higher drawdowns. Note that increased production over the long term must be supported by good reservoir management and voidage-replacement practices. Lowering the flowing bottomhole pressure can improve a well’s access to reserves in stratified reservoirs. Pumps also reduce the burden on the gas-compression system and enable selling gas or reallocating it to other gas lift wells. ESPs have a small topside footprint, do not impair subsurface-safety-valve operation, can achieve high production rates, and can aid fluid processing on production facilities because high-pressure power fluid or gas is not required. However, it can be difficult to determine the best ESP candidates when faced with numerous opportunities, limited resources for reserves studies or artificial-lift analyses, and finite installation capital. ESPs can help maximize an asset’s profitability, and screening criteria can streamline the candidate-selection process. These screening criteria were developed for dry-tree offshore applications. The high complexity, cost, and risk involved with subsea ESP installations and workovers typically have limited subsea pumping to seafloor technologies such as subsea separation, multiphase pumps, cartridge ESPs, and caisson ESPs. This trend may change with continued progress in alternative ESP-deployment/-retrieval technologies and/or run-life and reliability improvements.
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21063, ’Indonesian Operator's First Fieldwide Application of Intelligent-Well Technology - A Case History,’ by Kim Sam Youl, and Harkomoyo, SPE, Kodeco Energy Company and Doug Finley, SPE, Halliburton, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. A fieldwide application of intelligent-well-completion technology was used in Indonesia to commingle “free energy” from an overlying gas cap to support production from underlying oil reservoirs that typically have a high water cut. Previously, wells in this offshore field were developed with conventional gas lift completions that used gas supplied from outside the platform. The application of an “auto-gas-lift” (AGL) concept, an intelligent-well technology, eliminated the capital equipment associated with conventional gas lift completions along with the conventional downhole gas lift equipment. Introduction The KE-38 field is in the East Java basin, approximately 30 miles off the northern coast of Madura Island, Indonesia (Fig. 1). Water depth averages approximately 190 ft in this block. The oil columns are between 60 and 300 ft thick, with a 500-ft-thick gas cap (on average) and an underlying water zone. True vertical depth of the gas/oil contact is 4,500 to 5,000 ft subsea. Porosity of the oil rim ranges from 18 to 26%, and permeability ranges from 20 to 100 md. The reservoir is normally pressured, and productivity ranges from 5 to 20 bbl/(psi-D). Maximum bottomhole pressure and temperature are 2,200 psi and 195°F, respectively. The oil is a slightly waxy, 35°API crude. Given that the reservoir fluid is nearly saturated, initial production from the wells was with natural flow. However, because the flowline pressure is high (approximately 900 psi), these wells would require artificial lift during the initial stage of operation to begin flow and maintain the gas/liquid ratio to optimize the produced-oil rate. Conventional gas lift completions have a setting-depth limitation relating to the gas lift mandrel. The maximum setting angle is less than 60°. However, an AGL interval-control valve (ICV) is capable of being set in any trajectory angle and can be set at the deepest point in the wellbore to optimize oil production. The AGL completion enables altering the flow characteristics of a zone without mechanical intervention.
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13327, ’Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar,’ by Kristian Mogensen, SPE, and Soren Frank, SPE, Maersk Oil Qatar, and Rashed Noman, SPE, Qatar Petroleum, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The planning and implementation of a lean-gas-injection trial conducted in the low-permeability Kharaib B carbon-ate reservoir of the Al Shaheen field, offshore Qatar, is described. The main objectives of the trial were to determine whether premature gas breakthrough would occur in the neighboring production wells and whether water injectivity after the gasflood would be reduced as a result of the presence of high gas saturation around the injection well. Introduction The Al Shaheen field began production in 1992 from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. Field development used horizontal wells, some placed in radial patterns and others in parallel line-drive patterns of alternating water injectors and oil producers. These carbonate reservoirs are relatively thin oil columns with a large areal extent (25×45 km) with permeabilities in the 1- to 10-md range. The reservoir-fluid properties exhibit large lateral variations, with oil gravities ranging from 16 to 38°API within the same reservoir. The field contains several gas caps and shows large variations in solution gas/oil ratio (GOR) and in saturation pressures. Development studies focus on expanding of the current waterflood and on enhanced oil recovery (EOR). A promising EOR process is water-alternating-gas (WAG) injection that uses either CO2 or hydrocarbon gas as the injectant. A coordinated effort was initiated in 2006 to evaluate the scope for incremental field oil recovery. An important part of the EOR evaluation was to conduct an early gas-injection trial for a period of 6 months in the Kharaib B reservoir. The purposes of the trial were to investigate whether unexpected large-scale permeability heterogeneities exist in the reservoir, to gather gas- and water-injectivity data, and to gain experience for planning potential WAG-injection applications for the whole field. Planning Phase The most important part of the preparatory phase was to select the correct injection well for the trial to ensure that the trial objectives could be met. Once selected, the required modifications to the surface facilities then could be scheduled and a data-gathering program set up.
- Asia > Middle East > Qatar > Arabian Gulf (0.88)
- Asia > Middle East > Qatar > Ad-Dawhah > Doha (0.25)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124926, ’Real-Time Diagnostics of Gas Lift Systems Using Intelligent Agents: A Case Study,’ by G. Stephenson, SPE, Occidental Petroleum; R. Molotkov, SPE, Weatherford; and N. De Guzman, SPE, and L. Lafferty, SPE, Intelligent Agents Corporation, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October; revised for publication. The paper has been peer reviewed. Published: February 2010 SPE Production & Operations, page 111. One problem related to the operation of gas lift wells is the ability to identify underperforming wells and to address the underlying issues appropriately and in a timely manner. This problem is compounded by a trend toward leaner operations and relative scarcity of application-specific domain knowledge. A method is presented that leverages real-time data, gas lift domain expertise, and proven steady-state analysis techniques in a desktop software application. Introduction For cases in which these resources are limited or unavailable, automation technology could be a solution. To assist production engineers in the well-by-well optimization of gas lift systems, a system was developed that uses intelligent software agents that leverage both real-time data and gas lift domain knowledge to assist engineers in these well-by-well optimization tasks. Challenges With Historical Approach One of the most fundamental challenges is that the historical approach tends to be both reactive and episodic in nature, resulting in missed opportunities for production enhancement. Much of this work requires individuals with specialized artificial-lift-domain expertise, which is increasingly scarce as the demographics of the industry change. The ability to detect and address the numerous opportunities in a field is limited by the labor-intensive nature of the work and the volume of competing priorities. It is common for problems in gas lifted wells to go undetected for months or even years because gas lift is such a forgiving artificial-lift method. Even those gas lifted wells that have a serious performance problem and are not producing optimally will often continue to produce fluids. With other forms of lift, failures tend to be catastrophic in nature and are identified and addressed much more quickly. Addressing the Need A system was developed to provide real-time diagnostics of continuous gas lift wells. The system enables decisions that optimize wells. The system provides engineers with the status of all gas lifted wells under their control. Software agents monitor the wells’ situation by collecting and filtering data, assessing the meaning of those data, recommending actions for correcting problems and responding to threats, and explaining their assessment results and recommendations. Agents can detect the initial symptoms of a problem and prompt for corrective action before well performance degrades seriously. The performance of these key functions enables surveillance engineers to optimize many more wells on a continuous basis. The agents integrate continuous data, such as pressure readings, with well-test data and predictions from commercially available systems-analysis tools, and use diagnostic principles stored in a knowledge base to determine each well’s condition and recommend corrective action. The agent reviews all gas lifted wells in the field and prioritizes recommended actions in accordance with pre-established criteria that include increased production potential and possible cost efficiencies.
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 117489, "SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont," by T.C. Handfield, T. Nations, SPE, and S.G. Noonan, SPE, ConocoPhillips, prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed. Gas lift completions for steam-assisted-gravity-drainage (SAGD) producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used because of the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole through open-ended tubing or nozzles, which, if not properly sized, can result in operational issues that negatively affect the overall lift efficiency. Data were collected and analyzed to determine the efficiency of two types of gas lift nozzles used in the completions. The method for optimizing SAGD gas lift systems is presented, and recommendations are made for future improvement. Introduction Surmont, an oil-sands project, is approximately 37 miles southeast of Fort McMurray in the Athabasca oil sands in Canada. The Surmont pilot began steam injection in 1997, comprising three SAGD-well pairs that use a variety of artificial-lift methods. These wells were tested to determine the preferred method of artificial lift for the first commercial phase. Main steam injection was initiated in mid-2007, and conversion to full SAGD production followed in late 2007. Phase 1A comprises 20 well pairs in which all the producers were completed to produce by use of gas lift for the initial life of the well. Phases 1A, 1B, and 1C have a capacity of 25,000 B/D and are expected to reach peak production in 2012. A second phase is slated for commercial startup before the middle of the next decade, which, upon completion and full ramp-up, is estimated to bring peak production from both phases to 100,000 B/D. Additional phases at Surmont are under study. Historical Perspective The Surmont gas lift experience began with trials in two of the three pilot wells. The completions consisted of a single production string varying in size from 3.5 to 5.5 in. with a 1-in. coiled tubing (CT) run concentrically for gas lift and landed at the heel of the well. The bottom 2 m of the gas lift string was constructed similar to a perforated stinger with ten 11-mm orifices. These gas lifted wells operated with reservoir pressure as low as 334 psi, producing fluid rates between 1,047 and 3,352 B/D, with gas lift rates ranging from 211 to 339 Mscf/D for a total combined operating time between the two wells of 35 months. The conclusion from testing at the pilot was that gas lift at the higher reservoir pressures was effective. However, before making additional designs and sensitivity studies, the gas lift assemblies were removed to allow for testing and validation of other forms of artificial lift for Surmont SAGD.
- North America > Canada > Alberta > Athabasca Oil Sands (0.70)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- North America > Canada > Alberta > Census Division No. 16 > Regional Municipality of Wood Buffalo > Fort McMurray (0.25)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19455, "Mature Offshore Field Rejuvenation via Long-Reach Wells and Massive Hydraulic Fracturing: The Kitina Case History," by F. Okassa, SPE, L. Tealdi, D. Baldini, A. Casero, H. Malonga, D. Isella, A. Baioni, L. Riccobon, G. Obondoko, F. Itoua Konga, F. Pounga, and M. Rampoldi, SPE, Eni Congo, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. Many West Africa offshore fields are maturing, and operators are completing secondary targets to maintain economical operation. However, the level of capital expenditure for interventions is critical. In the Kitina field, offshore Pointe Noire, Congo, deeper sands have been produced to economic depletion and reservoir studies indicated alternative production intervals. Reservoir modeling; operation geology; and drilling, completion, and production challenges encountered in the 2007 Kitina rejuvenation campaign are described. Introduction The Kitina field, discovered in 1991, has five reservoirs.3A—limestone and sandstone with silty clay 2A—limestone: oolitic grainstone/packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement 2A—south accumulation: oolitic grainstone/packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement 1A—sandstone with carbonate cement and limestone 1B—sandstone with carbonate cement and limestone Three reservoirs (2A, 1A, and 1B) were depleted with a peripheral water-injection scheme and crestal gas injection. The initial production rate of the field was approximately 50,000 BOPD (1997), declining over a 10-year period to 7,000 BOPD. As the field depleted, some wells were put on artificial lift, initially with electrical submersible pumps and currently with gas lift. The recovery factors have been estimated at 15% for Reservoir 1B and between 25 and 30% for Reservoirs 1A and 2A. To initiate rejuvenation of the fields, it was decided to perform a full review of field potentials, which led to the following decisions.Optimize the recovery from Reservoir 3A (previously considered as marginal because of low permeability and the low production rates of the three wells already completed) by use of a massive hydraulic-fracturing campaign. Drill a long-reach and ultradeep well (KTM-SM5) in the south field structure into the Reservoir-2A south accumulation. Reservoir 3A Potential production from Reservoir 3A was studied by correlating with a similar sequence in another field, the Sounda marine field, 8 km east of Kitina. The formation permeability to oil ranges from 2 to 7 md. Three wells have been completed in this reservoir. Each well was produced as natural flow, but was completed with gas lift mandrels to accelerate well cleanup. Reservoir-3A production potential, from those three wells, was approximately 800 BOPD.
- North America > United States > Illinois > Madison County (0.25)
- Africa > Republic of the Congo > Pointe-Noire > Pointe-Noire (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.87)
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18820, "The Use of Subsea Gas Lift in Deepwater Applications," by Subash S. Jayawardena, George J. Zabaras, SPE, and Leonid A. Dykhno, Shell Global Solutions, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. Riser-base gas lift is used in subsea developments for production enhancement. It is an effective method to suppress severe slugging that occurs in flowlines with downhill inclination. In some cases, gas lift can aid blow-down for hydrate prevention. Gas lift is not always needed because its effectiveness depends on reservoir performance, fluid properties, seabed terrain, subsea architecture, and flowline and riser specifications. The need for gas lift, optimal operability, and system design should be assessed from various aspects, including flow assurance. A generic set of guidelines was developed on the basis of past experience with riser gas lift applications for different deepwater subsea projects and associated multiphase-flow phenomena. Introduction This paper discusses riser-base gas lift for deepwater subsea oil-production systems. The focus is how flow-assurance concerns affect various engineering decisions in designing a gas lift system. Riser-base gas lift is injection of a predetermined rate of gas from the host facility into the production flow-line (riser) at the seafloor. The reasons for gas lifting can vary, but the most important pertain to flow assurance, production enhancement, flow stabilization, and flowline depressurization. Why Gas Lift Is Needed The stages of a field's life should be studied to determine when to install and operate the gas lift system. Gas lift is not always beneficial; in some cases, increasing the gas rate may be detrimental to the performance of the subsea system. Production Enhancement. Gas lift for production enhancement lowers the flowline pressure. Typically, gas lift is needed with high water cuts in the flowlines, low-GOR fluids, and low-to-moderate production rates. The effectiveness is higher in systems with low production-system-inlet pressures. One major advantage of gas lift for production enhancement is that there are no moving parts in the subsea system, apart from valves and chokes. Compression for gas export is almost inevitable in any subsea development; therefore, the supply of lift gas during production is not a major issue. When to use gas lift for production enhancement should be determined by use of integrated (reservoir/wells/flowline) production modeling. The study also should include the water/gas injection to the reservoirs. Accuracy of flowline/riser pressure-drop and liquid-holdup calculations in multiphase-flow models and the accuracy of pressure/volume/temperature predictions are crucial. This accuracy becomes more important in larger-diameter flowlines with deepwater risers in which the multiphase behavior is different from that in smaller-diameter systems.
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101067, "Usari BQI Redevelopment - Paradigm Shift," by F.R. Alege, SPE, W.R. Brock, SPE, J. Linscott, B. Olopade, C. Etta, SPE, and L.K. Chen, SPE, Mobil Producing Nigeria, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. Developing low-gravity-oil reservoirs is not common in the Niger Delta. The Usari Base Qua Iboe (BQI) reservoir is an example of a heavier-crude-oil reservoir (18 to 20°API) in a field of approximately 35 more-conventional reservoirs (32 to 44°API). Until recently, this waterdrive reservoir had been developed only partially because of the crude-oil gravity, adverse oil/water mobility, and a strategy of low producing rates to avoid producing at high water cuts in the 70-ft-thick oil column. A study of analog fields in Nigeria and Western Australia led to a redevelopment campaign, which resulted in a nearly 10-fold increase in production and a significant improvement in reserves in less than 12 months. Introduction The Usari field, 15.5 miles offshore from the Qua Iboe Terminal in Akwa Ibom State in southeastern Nigeria, was discovered in 1964. In addition to the discovery well, four appraisal and 32 development wells have been drilled. Twelve wells penetrated the BQI reservoir and provided good well control for delineating the reservoir and establishing fluid contacts. In total, 35 reservoirs have been discovered in the Usari field. These reservoirs have been subdivided into three main zones on the basis of fluid properties, pressure regimes, and geologic setting. These categories are commonly referred to as the shallow (18 reservoirs), intermediate (15 reservoirs), and deep (two reservoirs). The fluid gravities for these categories range from 20°API for the BQI (shallow) to 44°API for the 2-US6 (deep). Fluid viscosity ranges from 5.6 cp in the BQI to approximately 0.3 cp for the intermediate reservoirs and 0.2 cp for the deep reservoir. The BQI reservoir, with more than 20% of Usari's original oil in place, has a relatively low solution-gas/oil ratio (183 scf/STB). The oil is more viscous (5.6 cp) and dense (20°API) than other area crude oils. The reservoir has a 70-ft-thick oil column with a gas cap approximately 60% of the size of the oil accumulation. The reservoir is mainly upper-to-lower shoreface sands with good lateral continuity and high permeability with a moderate-to-strong waterdrive. The low-API-gravity oil (density close to that of water) and the low gas content make gas lifting a requirement to produce this viscous oil. History The first BQI reservoir-development efforts began in 1967 after drilling the Usari-3 appraisal well and installing the first wellhead platform in the field. This vertical well was completed as a producer in the BQI reservoir but died because of low wellhead pressure in less than 1 year with a lack of gas lifting capability. Well Usari-3 subsequently was plugged and abandoned. Development of the BQI reservoir was resurrected in 1999 with two horizontal wells, Wells 20B and 21B, followed by horizontal Wells 23C and 24C in 2001. These four wells were landed approximately in mid-column and had horizontal completion intervals ranging from 1,500 to 2,000 ft. The wells had 7-in. casing cemented to surface and were completed with 2 7/8-in. tubing equipped with gas lift mandrels.
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta (0.56)
- North America > United States > Texas (0.54)
- Oceania > Australia > Western Australia (0.35)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 70 > Usari Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 123 > Ebughu Field > Agbada Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-14-L > Wandoo Field (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > Block WA-202-P > Wandoo Field (0.98)
When the well is first than the water cut at which the well will Dynamic Modeling opened after the shut-in period, the column naturally stop flowing. Four oil wells were modeled with commercial of gas is produced from the tubing, leaving Four undersaturated-oil fields with eight software, and several simulation runs a higher-density mixture of oil, water, and wells producing through a subsea system to were performed to investigate a future kickoff new reservoir fluid. The flowing bottomhole the Cossack Pioneer floating production, problem in the Wanaea, Lambert, and pressure (FBHP) of the well reaches a storage, and offloading vessel were studied.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > Rankin Platform > Block WA-16-L > CWLH Field > Lambert Field > Lambert 4 Well (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > North West Shelf > WA-28-P > CWLH Field > Wanaea Field > Wanaea 7 Well (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > North West Shelf > CWLH Field > Cossack Field > Angel Formation (0.99)
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