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Collaborating Authors
Introduction The super Giant Kashagan field is located in a shallow-water (ice-locked during the winter), environmentally sensitive area of the Kazakh sector of the North Caspian Sea. The Kashagan field was discovered in 2000 by a consortium of oil companies. The current North Caspian PSA companies are affiliates of: ENI, ExxonMobil, Shell and TOTAL, each with 18.52% share, Conoco-Phillips (9.26%), Inpex and KazMunaiGaz (8.33%, each). Agip KCO (an ENI company) operates the field. The Kashagan field is a deep, over pressured (initial reservoir pressure: 783 bar), isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low- permeability, stratified, platform interior. The field contains a 43-degree API light oil, with 15% H2S and 5% CO2, and contains more than 100 Tcf of associated gas. One of the biggest challenges of the Kashagan field development is the management of huge volumes of highly sour associated gas. The consortium had essentially two options to address this challenge:A commercially unattractive, but technically not challenging, conventional choice of evacuating the sour gas to shore for treatment (H2S and CO2 removal) and sales; or A technically very challenging, but potentially economically beneficial, alternative of injecting the raw sour gas back into the reservoir. This injection alternative, with its high discharge pressures and sour service, would extend the current capabilities of existing gas compression technologies. Nonetheless, it had the potential to significantly enhance oil recovery, as the Kashagan oil and injected gas are first contact miscible at pressures well below the initial reservoir pressure. Before proceeding with such a decision (after all, miscible gas injection is usually a secondary, or even a tertiary, recovery technique), the consortium had to undertake extensive evaluations to ascertain the likelihood of subsurface and surface risks. The paper describes the integrated approaches and the different technologies brought to bear to evaluate the likelihood of potential risks (such as breaching of cap rock integrity, early gas breakthrough or asphaltene precipitation), and to implement mitigating solutions. It presents the reservoir and gas management strategies to mitigate the risks of cap rock failure and premature gas breakthrough. It also mentions some of the technologies advocated to, notably, detect potential fracture growth, monitor gas front movement and shut-off high gas-oil ratio producing zones, efficiently and cost-effectively.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (4 more...)
Overcoming Formation Damage in a Carbonate Reservoir Rock due to Asphaltene Deposition
Altemeemi, Bashayer (KOC) | Gonzalez, Fabio A (BP Kuwait) | Gonzalez, Doris L (BP America) | Jassim, Sara (KOC) | Snasiri, Fatemah (KOC) | Al-Nasheet, Anwar (KOC) | Al-Mansour, Yousef (KOC) | Ali, Abdullah (NAPESCO) | Sheikh, Bilal (NAPESCO)
Abstract Asphaltenes flow in equilibrium with the liquid phase as other components of the produced hydrocarbon. If asphaltenes are in solution during production, there are not negative impact to well productivity. However, asphaltenes could precipitate as pressure, temperature and composition change. If precipitated, due to pressure decrease, asphaltene could deposit as a solid phase in the formation rock near wellbore becoming an obstruction to flow and inducing formation damage. Skin due to asphaltene deposition near wellbore was confirmed in several wells of a carbonate reservoir. Asphaltene deposition was also observed in the production tubing. The objective of this work is to investigate the main variables affecting asphaltene deposition in the Magwa-Marrat field is South East Kuwait and develop a technique to manage and/or decrease formation damage due to this solid deposition phenomena. In order to estimate the skin value and predict the location of any impairment to production, a pressure gauge was set at 1,000 ft above the top of the perforations and the well was equipped with a permanent multiphase meter device. A series of pressure buildup tests and multi-rate tests were run to disseminate Darcy skin from non-Darcy skin. Pressure transient analysis (PTA) delivered total abnormal pressure losses from the formation near wellbore to the gauge location, while multi-rate tests (MRT) allowed to investigate rate dependent skin. Well tests at different rates were also run to investigate the relationship between fluid velocity and asphaltene deposition. Once the elements of total skin were split into Darcy skin and Non-Darcy skin, a tubing clean-out and a stimulation job were designed and implemented to eliminate the asphaltene deposits and remove the damage. Total skin was reduced from +30 to −3.5 and productivity index was increased by a factor greater than ten (10). The production rate to mitigate asphaltene deposition was successfully determined. The well has been on production for about 1 year without developing any additional damage and without further deposition of asphaltene in the production tubing as the well has been flown above the minimum flow velocity that would allow asphaltene deposition. A combination of well intervention combined with determination of operating conditions have been developed to successfully produced asphaltenic hydrocarbons at flowing bottom hole pressure (FBHP) below asphaltene onset pressure (AOP). This methodology has been successfully implemented. If the liquid velocity is high enough to carry precipitated asphaltene out, solid deposits are not observed and there is not harm to productivity. The technique has worked for a case where reservoir pressure has been depleted below asphaltene onset pressure (AOP). This is a fundamental change in the globally applied industry approach that urges to produce asphaltenic hydrocarbons at FBHP above AOP.
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Umbilical Deployed Stimulations for Asphaltene Related Damage in Offshore Oil Fields
Peruzzi, T.. (Murphy Exploration & Production) | Coulon, T.. (Murphy Exploration & Production) | Fauria, J.. (Murphy Exploration & Production) | Frey, D.. (Murphy Exploration & Production) | Marechal, H.. (Murphy Exploration & Production) | Sloan, R.. (Murphy Exploration & Production)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 15-17 February 2012. 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.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.73)
Abstract Preventing scale precipitation is one of the main issues for maintaining well productivity on the Veslefrikk Field 1.An oil soluble scale inhibitor treatment was pumped that reduced the initial productivity index (PI) from 21 Sm[3]/d/bar to 3 Sm[3]/d/bar. Reperforation only restored some of the productivity (from 3 to 7 Sm3/d/bar) indicating deeper near wellbore damage. A small hydraulic fracture stimulation was then performed, creating a propped fracture with a half-length of approximately 6 m. The PI then increased to 30 Sm[3]/d/bar, a 43% increase from the initial value. The stimulation was performed under pressure through a 2 7/8" work string run on Rig Assist Snubbing (RAS) with pumps and blenders rigged on the pipe deck. Introduction The Veslefrikk Field is located in block 30/3 on the Norwegian sector of the North Sea. The field is developed with a fixed wellhead platform with 24 well slots, connected to a floating production facility.Original recoverable reserves were estimated to 36 million Sm[3] of oil to be developed during 10 years of production starting from 1989. Today approximately 45 million Sm[3] has been produced and still close to 10 more million Sm[3] is planned to be produced. The producing reservoirs are in the Brent Group, the Intra Dunlin Sand and the Statfjord Formation (Figure 1), each containing a different fluid system. The main pressure support is from sea water injection. Although the ion composition of the Veslefrikk formation waters are not extreme compared to other North Sea formation waters, severe scale precipitation has occurred. Both CaCO[3] and BaSO[4] have been identified, enhanced by high reservoir temperature, 125º C (CaCO[3]), and commingled production (BaSO[4]). A preventive scale control strategy[1] mainly based on scale inhibitor treatments has been implemented. Pre stimulation well history Well 30/3-A-24 T2 was initially perforated in two 3 meter intervals in the upper part of the Oseberg Formation. This is relatively clean, moderate porosity sandstone with permeabilities in the 100 – 1000 md range. Calcite cemented and shaly layers have been observed in some areas of the field, but the lateral communication is good. To allow for zone selective water shut-off (straddle) or zone selective fracturing, the two perforation intervals were separated by 8 meter. The well was put on production on the 19th of May 2002, and a step rate test indicated a liquid productivity index (PI) of 21 Sm[3]/d/bar. Formation water breakthrough occurred after 2–3 days of production, and the subsequent well tests showed decreasing PI. This was interpreted to be due to deposition of calcium carbonate in the perforation tunnels and in the liner (confirmed by later wireline interventions), and a scale inhibitor squeeze was therefore initiated. Previous scale squeezes in low water cut wells on the field have often resulted in decreased PI and increased water cut, probably due to relative permeability effects. To avoid this it was decided to deploy a scale inhibitor dissolved in an organic solvent (Oil Soluble Inhibitor, OSI). When these chemicals get in contact with the connate water, the inhibitor will transfer to the connate water and remain in the pores. After water break-through the inhibitor is activated and protects the produced water from scale precipitation. This was the first OSI to be performed on Veslefrikk, the supplier reported a success rate of almost 100% (approximately 30 jobs), and the field specific laboratory tests and core floods showed acceptable results. The OSI treatment was performed the 30th of May 2002. During the pumping sequence high pressures were observed for a longer period than expected, but the squeeze was nevertheless completed. Fracturing pressure was never exceeded. It soon became obvious that the treatment had caused severe formation damage. Well tests showed that the PI had decreased to 3 Sm[3]/d/bar as a result of the OSI squeeze, Figure 2.
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Geology > Mineral (0.35)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- Europe > Norway > North Sea > Northern North Sea > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Uer Terrace > PL 079 > Oseberg Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 190 > Brent Group > Tarbert Formation (0.99)
- (6 more...)
Production started in 1994, through 4 The Stattjord East and North are two sub sea tields tied in to the production templates. Pressure support is maintained through 2 Statijord C platform on the Stattjord Field.
- Europe > Norway > North Sea (0.48)
- North America > United States > Texas (0.47)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.99)
- (5 more...)