Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Block RJ/ON-90/1
Summary This paper presents a systematical review of the largest polymer flood project in the world, applied to multilayered, heterogeneous sandstone reservoirs in the giant Daqing Oilfield in China. First, reservoir and fluid characteristics are highlighted to understand the heterogeneity of the reservoir. Next, the project history is summarized, including laboratory studies, pilot tests, commercial tests, and fieldwide applications. Third, typical polymer flood performance and reservoir management measures are presented. Finally, key understandings and lessons learned from more than 50 years of experience are summarized. The La-Sa-Xing Field in the Daqing Field Complex contains three types of reservoir sands: Type I sand with high permeability, Type II sand with medium permeability, and Type III sand with low permeability. Polymer flood was studied in the laboratory in the mid 1960s, followed by small-scale pilots beginning in 1972 and industrial-scale pilots starting in 1993, all of which successfully reduced water cut and enhanced oil recovery. Fieldwide application commenced in 1996, targeting the Type I sand. With Type II sand being brought onstream in 2003, the project achieved a peak production of 253,000 BOPD in 2013. Polymer flood reduced water cut by 24.8%. Reservoir management measures, such as zonal injection, profile modification, hydraulic fracturing in low-permeability sand, and injection optimization, proved to be effective. Based on the water-cut performance, production can be divided into four stages: (1) water-cut decline, (2) low water cut, (3) rebound, and (4) water chase. Fit-for-purpose improved-oil-recovery measures were implemented for each stage to improve production performance. Key understandings and lessons learned include the following: (1) Polymer flood improves both sweeping and displacing efficiencies; (2) high interlayer permeability contrast leads to low incremental recovery; (3) variable well spacing should be adopted for different reservoir types; (4) adoption of large molecular weight (MW) and large slug size greatly enhances recovery; and (5) salt-resistant polymer is beneficial for produced water reinjection in Type II sand; (6) zonal injection increased swept reservoir zones by 9.8% and swept pay thickness by 10.3%; (7) profile modifications helped improve vertical conformance in injection wells and led to enhanced sweeping efficiency and extended low water-cut stage; and (8) optimization-recommended well spacing for Type I, Type II, and Type III sands is 10–15.5, 5.6–7.6, and 2.5–3.6 acres, respectively. In comparison with generally 6–8% incremental recovery by polymer flood in the industry, this project achieved an impressive incremental recovery of 12%, enhancing the oil recovery factor from 40% by primary recovery and waterflood to 52% stock tank oil initially in place (STOIIP). The progressive approach from laboratory experiments through pilots and finally to field application is a best practice for applying polymer flood fieldwide for a giant field such as the La-Sa-Xing Field.
- Asia > China > Heilongjiang Province > Daqing (0.49)
- North America > United States > Gulf of Mexico > Central GOM (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geology > Sedimentary Geology > Depositional Environment (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.68)
Coreflood-on-a-Chip Investigation of Oil Bank Formation in Low Interfacial Tension Chemical Floods at Favorable and Unfavorable Viscosity Ratios
Mejia, Lucas (The University of Texas at Austin (Corresponding author)) | Du, Yujing (The University of Texas at Austin) | Balhoff, Matthew T. (The University of Texas at Austin)
Summary An efficient tertiary chemical flood involves the chemicals displacing the oil in a stable manner, so the initially disconnected trapped oil ganglia coalesce into a bank as the flood progresses. However, the location of surfactants and polymers in the core during a chemical flood is difficult or impossible to determine at very fine time and space resolutions. In this work, we bridge this gap by visualizing saturation profiles in a coreflood-on-a-chip, a micromodel that is the same length as a core, and monitoring fluorescent aqueous injectant as displacements occur. We visualize, for the first time, surfactants in and around oil banks at the pore and Darcy scales during low-tension displacements. We present 12 chemical floods in the coreflood-on-a-chip, imaged at the centimeter scale, including six surfactant and six alkali-surfactant-polymer (ASP) floods at low, intermediate, and high initial water saturations. Additionally, we present a micron-scale visualization of an ASP flood under UV light to observe the distribution of surfactant around an oil bank at the pore scale. We found that oil banks formed even during very unfavorable displacements, when surfactant solution (1 cp) displaced oil (80 cp) in a micromodel at intermediate and residual oil saturations. Although our results show saturation profiles are mostly well described by fractional flow theory, the distribution of injected aqueous phase is not. Significant aqueous injectant, including surfactant, flows within and ahead of oil banks.
- Asia > Middle East (0.68)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
A New Logistically Simple Solution for Implementing Alkali-Surfactant-Polymer/Alkali-Cosolvent-Polymer in Difficult Environments: Evaluation of Concept with High Total Acid Number Viscous Crude Oil
Southwick, Jeffrey George (JSouth Energy LLC (Corresponding author)) | Upamali, Nadeeka (Ultimate EOR Services, LLC) | Fazelalavi, Mina (Ultimate EOR Services, LLC) | Weerasooriya, Upali (Ultimate EOR Services, LLC) | Britton, Chris (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC)
Summary Research on alkali-assisted chemical enhanced oil recovery (EOR) technology [alkali-surfactant-polymer (ASP)/alkali-cosolvent-polymer (ACP)] with high total acid number (TAN) crude oils has led to developments with liquid organic alkalis and cosolvents (Southwick et al. 2020; Fortenberry et al. 2015; Schumi et al. 2019; Upamali et al. 2018). Both concepts afford potential significant cost reduction in field operations, but to date it has not been demonstrated that these two concepts can work together. Monoethanolamine (MEA) alkali and a wide variety of liquid cosolvents are evaluated with high TAN crude oil (1.5 mg KOH/g oil). Formulations are found that give ultralow interfacial tension (UL-IFT) at a specified injection salinity. Fine tuning the formulation to different injection salinities can be done by choosing alternate cosolvents (or a cosolvent blend). A formulation comprising 1% MEA and a novel high molecular weight (3152 g/gmol) cosolvent, 0.5% glycerin alkoxylate with 30 mol of propylene oxide and 35 mol of ethylene oxide (glycerin-30PO-35EO), gave UL-IFT in 21,000 total dissolved solids (TDS) injection brine and gave 100% oil recovery in Bentheimer sandstone with 3,500 ppm FP 3630Ss (SNF Flopaam 3630Sis partially hydrolyzed polyacrylamide) as mobility control agent. All oil was produced clean, no separation of emulsion was needed to measure oil recovery. Alkali consumption tests were also performed with a high-permeability reservoir sandstone. Results confirmed earlier data published with Boise outcrop sandstone (Southwick et al. 2020) showing low alkali consumption with MEA. On a mass basis, only 12% of the amount of MEA is consumed relative to the amount of sodium carbonate consumed. This reduces the logistical challenges of shipping chemicals to remote locations. MEA is also a low-viscosity liquid which further simplifies field handling.
- Asia > Middle East (0.47)
- North America > United States > Idaho > Ada County > Boise (0.24)
- North America > United States > Oklahoma (0.16)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- (2 more...)
Abstract This paper explains the importance for implementation of early water flood in near saturation pressure oil reservoirs particularly for the case having solution gas as dominant drive mechanism. The depletion in case of solution-gas drive (having no or minor support) with low to moderate in-place volumes is relatively fast. It is commonly observed that no pressure maintenance program is implemented till the reservoir pressure has been severely exhausted. This delay is generally caused by time consumed during understanding of fluid and reservoir behavior, and ultimately symbolizes the phrase ‘missing the train’. The objective of this study is to present the importance of early water flood and its impact on oil recoveries. A field was discovered in South Indus Basin which has half graben and four-way fault bounded structure with numerous splay faults. A well was drilled which encountered Sands ‘A’ and initially produced ~1360 bopd having ~4500 psia initial reservoir pressure. A detailed study was carried out when the reservoir pressure had depleted from 4500 to 1200 psia after draining ~400 MBO with ~1 Bscf associated gas. Based on the outcomes of the study, water flood was implemented by drilling an injector well ‘Inje-1’ which increased the pressure from 1200 psi to 4500 psi in the later life of field. Despite the pressure had rose to initial reservoir pressure, the recovery from the reservoir remained sub optimal. To understand the importance of implementing early water flood at higher pressures, a numerical simulation model was developed, history matched, and various sensitivities were run to see the impact of water flooding at various reservoir pressures during the life span of the field. It was observed that the recovery would have been more if the water flooding was implemented when the reservoir pressure was above bubble point. The reason being liberation of gas and shrinkage of oil resulting in high viscosity and low mobility oil remaining behind. If this liberation of gas is prevented by injecting water and conserving reservoir energy, both viscosity and mobility of oil would remain favorable due to delay in arriving at saturation conditions. Hence the recovery of these types of reservoirs can be enhanced by taking advantage of low viscosity and higher mobility of oil during early life. If the waterflood is implemented after exhausting the reservoir pressure, then the increased viscosity restricts oil flow and causes water channeling due to higher mobility contrast. As a result, leaving behind bypassed oil zones and very high residual oil saturation. In the present case study, it was observed that if the water flooding was implemented prior to reaching bubble point, recoveries would be 7-15% higher as compared to previous recovery. The early implementation would have added value to the overall project. Implementing the lesson learned, recent new discoveries are being evaluated to initiate water flood in early life. Early implementation of water flood in the oil reservoirs closed to saturation pressures will always be beneficial. Appropriate field development plan of the field and right decisions at right time will aid to enhance oil recovery. Once the energy in the oil reservoir is drained after producing gas, it is very difficult to regain the same energy.
- North America > United States (0.93)
- Asia > India > Rajasthan (0.46)
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.54)
- Asia > Pakistan > Arabian Sea > Indus Basin (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- (4 more...)
Abstract Chemical injection has been identified as one of the upstream strategies by PETRONAS for maximizing oil recovery from a Malaysian offshore oil field which is currently operating under waterflooding and declining in oil production. A chemical application roadmap from laboratory to full field scale was established with numerous technical evaluation stages. The recipe and formulation for this chemical injection were obtained from inclusive laboratory experiments studies including chemical screening, fluid-fluid, and fluid-rock evaluations. Pilot field trial tests by single well chemical tracer (SWCT) technique were designed and executed to validate the laboratory results, chemical injection response, and to obtain an operating experience prior full field scale implementation. A simulation modelling study was carried out to obtain a scheme of injection, proper wells pattern, and amount of incremental oil recovery expected from this application. Moreover, an integration study from subsurface to surface including reservoirs, wells, and surface facilities were conducted to find an appropriate development concept and reduce the overall project costs for ensuring being a techno-commercially viable project. Laboratory results verifies that a chemical injection consist of 1.0 wt. % alkali and 0.075 wt. % surfactant in an optimum salinity range of 5,000-10,000 ppm and adsorption of 0.30 mg/gr-of-rock should establish an ultralow IFT of 0.001 dyne/cm system and result in 50-75 % Sorw reduction. Favorable results achieve from pilot testes where successfully mobilized substantial amounts of Sor and chemicals easily mixed with no injection problems encountered. They were consistent with laboratory findings and validated a 50-80 % Sorw reduction. Minimum residual oil saturation of 0.06 and 0.08 were seen after chemical application. Soft-water buffers were planned to minimize competing reaction of alkali and allow surfactant to work in more favorable lower salinity water and fortunately, results show that it was not severe enough to prevent the AS system from working. The contrast of initial waterflooding Sor after first pilot completion in two wells indicate an increase of 0.04 in Sorw (0.16 to 0.20 and 0.27 to 0.31) which, interestingly it could be due to a shift in rock wettability toward more water wet system. Modelling study shows a four-year plan including three-year of AS slug and six-month of pre and post buffers is an optimum injection scheme. This paper presents an outlook of the chemical project. This knowledge is extremely useful in guiding future laboratory studies and field implementation. Although, chemical was verified technically but significant efforts were made to gauge the development concept with harsh offshore environment, large well spacing, and chemical handling. This study can be used as a technical reference address various challenges that are often encountered in implementing chemical EOR, particularly at an offshore environment.
- Asia > Middle East (0.93)
- Asia > Malaysia (0.67)
- North America > United States > Texas (0.46)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > West Central Graben > PL2244 > Block 21/27a > Pilot Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > West Central Graben > P2244 > Block 21/27a > Pilot Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- (7 more...)
Mangala Polymer Flood Performance: Connecting the Dots Through In-Situ Polymer Sampling
Shankar, Vivek (Cairn Oil and Gas, Vedanta Ltd (Corresponding author)) | Shekhar, Sunit (Cairn Oil and Gas, Vedanta Ltd) | Gupta, Abhishek Kumar (Cairn Oil and Gas, Vedanta Ltd) | Brown, Alasdair (Cairn Oil and Gas, Vedanta Ltd (now with Rhynd Consulting LLC)) | Veerbhadrappa, Santhosh (Saskatchewan Research Council) | Nakutnyy, Petro (Saskatchewan Research Council)
Summary The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the stock tank oil initially in place (STOIIP) has been produced in 11 years. Mangala was put on full field polymer flood in 2015, 6 years after the start of field production on waterflood in 2009. Polymer flood added nearly 93 million barrels above the anticipated waterflood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Importantly, the observed polymer breakthrough deviated significantly from predictions. As the polymer flood matured, the trend of field water cut with time indicated that in-situ polymer viscosity was equivalent to only 50 to 60% of the surface polymer viscosity. For better predictions and corrective actions, it was necessary to understand the nature of degradation, the progressively deteriorating field performance, especially of the lower layers, and the deviation of polymer breakthrough trends from predictions. Carefully designed in-situ polymer sampling, laboratory studies, and reservoir modeling studies helped connect the dots to understand the field performance. There are several excellent publications on accelerated aging studies and some on polymer sampling. This paper offers an opportunity to directly compare experimental results with field data. The procedures used and lessons learned during field sampling can be useful for other operators for management of polymer floods.
- North America > United States (0.95)
- Asia > India > Rajasthan (0.89)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Completion Design and Hydraulic Fracturing Evolution in a Tight Reservoir Having Low Poisson's Ratio and Low Young's Modulus: A Case Study in Aishwariya Barmer Hill (ABH) Oil Field, Rajasthan, India
Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd) | Vijayvargia, Utkarsh (Cairn Oil & Gas, Vedanta Ltd) | Tiwari, Shobhit (Cairn Oil & Gas, Vedanta Ltd) | Gupta, Sumit (Cairn Oil & Gas, Vedanta Ltd) | Kothiyal, Manish Dutt (Cairn Oil & Gas, Vedanta Ltd)
Abstract Aishwariya Barmer Hill (ABH) field is a moderate permeability (0.5 – 4 mD) oil bearing porcellanite with alternating sequences of tight shale. After successful appraisal campaign a full field development with multi-stage fracturing using cemented frac sleeves, field was brought online with Hydraulic Sucker Rod Pump (HSRP) as artificial lift and has been on production since 2019. However, a need was felt to review the frac and completion design on account of challenges faced during fraccing and unplanned downtime during production operations. Critical observations that prompted a change in completion and frac technology are: Formation rock pebbles and proppant were observed in the wellbore during workovers. Reservoir's low Young's Modulus (YM) allows the generating high strains at low pressures, while low Poisons Ratio (PR) makes the rock brittle and shatter under high deformation. Consequently, shattered rock was not able to hold the proppant in place after fracture closure resulting into flowback of proppant and pebbles. Debris fill in wellbore resulted in production impairment and malfunctioning of HSRP. To mitigate the identified risks, the design change incorporates measures to address post fracturing production problems related to high treating pressures as well as optimize number of frac stages and stage spacing. Uniform proppant distribution with lesser number of stages is targeted by utilizing limited entry technique to help in distributing treatment pressures and proppant in multiple clusters as well as limit net pressure build up in each frac. It will help prevent rock shattering and better retention of proppant after frac closure. Completion design workflow includes log based zonal isolation between each stage and frac design for two to three cluster per stage. The revised design will predict the number of stages in each well for optimal utilization of wellbore for best economical production. Revised frac design has been implemented in 5 infill wells wherein 66 stages have been pumped without TSO signature or premature screen out in any of the stages. Wells have been put on production and are performing better than rest of the wells in the field. There has been no evidence of debris accumulation in wellbore or proppant flowback in production fluid. Further drilling campaign for 15 wells has been planned with cluster frac strategy with revised frac design.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Bhagyam Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Aishwariya Field > Barmer Hill Formation (0.99)
- (3 more...)
Two Decades of Mangala Field Journey - Key Highlights, Learnings and Recommendations
Prasad, Dhruva (Cairn, Oil & Gas vertical of Vedanta Limited) | Singh, Aditya Kumar (Cairn, Oil & Gas vertical of Vedanta Limited) | Shekhar, Sunit (Cairn, Oil & Gas vertical of Vedanta Limited) | Kumar, M Suresh (Cairn, Oil & Gas vertical of Vedanta Limited) | Pandey, Amitabh (Cairn, Oil & Gas vertical of Vedanta Limited)
Abstract The Mangala field in India was the first major oil discovery in the Barmer Basin having a STOIIP of nearly 1.3 billion barrels in multiple stacked fluvial reservoirs. It contains medium gravity (20-28 °API), waxy, viscous crude (9-17 cP) in high permeability (1-25 Darcy) clean sandstone reservoirs. The field was discovered in 2004 and brought online in 2009, one of the fastest from discovery to production phase. Hot water injection was started within few months of first production to sweep and maintain pressure. The hot water was essential considering wax appearance temperature (59 degC) close to reservoir temperature (65 degC). The hot water is also used as power fluid for jet pump (main lift system in field) and for annulus circulation in case of shutdown to avoid oil congealing. Jet pump application is the largest in the world with ~160 active wells lifting ~400,000 blpd reservoir liquid with ~500,000 bbls of power fluid. Plateau production of 125k bopd was achieved within 14 months from production start, which is one of the fastest among large onshore fields. The initial average oil rates in wells were ~2000-15000 bopd. Given the high well productivity, the field plateau rate was revised to 150k bopd within a year of achieving 125kbopd. Due to adverse mobility ratio with water, EOR screening and lab study was started right after discovery. Chemical EOR was identified as the most suited with polymer in the first phase followed by surfactant-based flood. Considering the EOR importance, a 5-spot polymer pilot was started almost simultaneously with the start of the field production. Basis pilot results, full-filed polymer flood was started from 2015 which is again one of the fastest EOR implementations. The polymer flood is one of the largest in world with 165 tons/day polymer consumption through ~500000 bwpd of polymerized water injection. Polymer flood reversed the production decline and is expected to give ~8% incremental recovery of STOIIP (~100 MMbbls) by 2030. Following polymer, a successful ASP pilot was conducted in the same wells/pattern which resulted in 20-25% incremental recovery of pilot STOIIP over polymer flood. Planning for large scale ASP implementation is underway. There have been several challenges and important learnings along the way including vertical conformance, areal VRR management, polymer development, degradation, viscosity and quality control over time, jet pump and ESP operations etc. Mangala field recovery has been quite fast with ~37% recovery within 13 years field life. Multiple infill campaigns have been conducted with ~280 wells drilled over 165 base development wells. The paper presents the development journey of Mangala from discovery to date with key achievements, many firsts, learnings and recommendations based on waterflood and polymer flood performance for other similar fields.
- Asia > India > Rajasthan (1.00)
- North America > United States > Colorado > Mesa County (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Mineral (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.34)
- Geophysics > Seismic Surveying (0.46)
- Geophysics > Borehole Geophysics (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (5 more...)
Design of In-Depth Conformance Treatment in the Mangala Polymer Flood Project
Zaitoun, Alain (Poweltec) | Omonte, German (Poweltec) | Bouillot, Jerome (Poweltec) | Salehi, Nazanin (Poweltec) | Bellin, Stephan (Cairn India) | Das, Joyjit (Cairn India) | Kumar, Ritesh (Cairn India) | Shekhar, Sunit (Cairn India) | Horn, Brian (Cairn India) | Ahmed, Abaan (Cairn India) | Kumar, Alok (Cairn India) | Sharma, Gaurav (Cairn India) | Kumar, Suresh (Cairn India)
Abstract The Mangala Field is located in the Barmer Basin in north-west of India (Fig. 1). The field has oil in-place volumes of 1.3 billion barrels, with an estimated recovery factor of 43% with polymer flood. Production began in 2009 and water injection in 2010. Polymer flooding started in 2015 in all layers at field scale. A successful ASP pilot was conducted in 201012 and it envisaged to roll it out gradually to full field in due course of time. The main reservoir units in the Mangala Field are the fluvial sandstones of the Fatehgarh Formation. The targeted reservoir horizon (FM1), is quite heterogeneous. The permeability range varies from 200 mD to several Darcies (4-5 Darcies) and sandbody connectivity is complex in the reservoir that is interpreted as a fluvial to lacustrine environment. This heterogeneity affects polymer sweep efficiency and calls for an in-Depth Conformance solution. Two candidate patterns were selected for further evaluation of conformance technologies. The selection criteria were based on early breakthrough, non-uniform injection profiles, cross-section analysis to check connectivities and low recovery factor with higher remaining oil. Several chemical conformance options were considered. Injection of gels are constrained by the gelation time, which does not typically exceed a few days. Injection of Microgels is preferred since the single component product acts by simple adsorption and can thus propagate deep in the reservoir. Moreover, the Microgel size which is above 2 μm, prevents the invasion of low-permeability intervals by a size-exclusion process. The product has thus a natural tendency to invade high permeability sandbodies (already swept). Different Microgel species have been submitted to lab tests. SMG Microgels keep their original size, while EMG Microgels expand with time and temperature. A major challenge to overcome is the existence of a polymer layer adsorbed on pore walls, which creates a barrier to Microgel adsorption. Finally, an EMG species whose chemistry induces high adsorption level has been qualified. The adsorption level is as high as 200 μg/g and the product induces a permeability reduction to water of around 8.5. Reservoir simulations were conducted afterwards to optimize the injection design (volume and duration) and draw performance forecasts. The reservoir simulation software used for the study can perform a dual polymer simulation, so two different species of polymers can be simulated. The sector model was made of two inverted contiguous 5-spot patterns with central injectors. The best scenario consisted in injecting the EMG at a concentration of 0.3% for 15-30 days. The deployment is simple since the product (delivered as liquid emulsion) can be injected with a volumetric pump of the water injection line directly. Additional oil production is expected to be as high as 95,500 bbls in 4.5 years. Microgel technology, has been successfully applied in waterflood projects in heterogeneous sandstone reservoirs and is shown to be applicable in ongoing polymer flood as remedial injection to solve conformance problems as well as produce significant incremental oil currently by-passed.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- (4 more...)
- 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 > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Time-Lapse Pulsed Neutron Logging Helps Maximize Recoveries from Mature Field - Case Study from Mangala Field of Rajasthan, India
Kumar, Alok (Cairn Oil & Gas, Vedanta Ltd.) | Sigtia, Shraddha (Cairn Oil & Gas, Vedanta Ltd.) | Das, Joyjit (Cairn Oil & Gas, Vedanta Ltd.) | Guha, Rupdip (Cairn Oil & Gas, Vedanta Ltd.) | Ahmed, Abaan (Cairn Oil & Gas, Vedanta Ltd.) | Shankar, Vivek (Cairn Oil & Gas, Vedanta Ltd.) | Kumar, Suresh (Cairn Oil & Gas, Vedanta Ltd.) | Chauhan, Nishi (HLS Asia Ltd) | Kumar, Ravinder (HLS Asia Ltd) | Ramakrishna, Sandeep (HLS Asia Ltd)
Abstract Mangala Oilfield of Rajasthan has produced over 36% of STOIIP and has been subjected to several innovative and new era technologies since it started producing in August’ 2009. Initially, field was under Water flood phase till April’2015 and then full field Polymer flood phase started to maximize recovery. Mangala field with medium-gravity viscous crude oil & formation water salinity of approximately 8000ppm has an excellent reservoir property of high porosity (24 to 26%), high permeability (200md- 20D) and very low irreducible saturation i.e., less than 5%. Thus, C/O logging in this field has been a very good choice to estimate the remaining oil saturation (ROS) and understand the sweep of oil due to injection which in turn has helped in maximizing recoveries from the field. Time-lapse PNL were run in several wells to monitor the efficacy of the water flood/polymer flood phase on oil recovery. The objective was two-fold; to estimate the change in saturation over time and to identify by-passed or marginally swept intervals. The process begins with recording the initial saturation in the wells before any production has occurred. Then time-lapse data are recorded to monitor the change in saturations. Secondly, saturation estimation from PNL data were used to plan the next course of action- workover operations, changing completion zones, abandoning certain zones or wells, and infill drillings. PNL data in combination with other reservoir surveillance techniques (MPLT) has proved to be a vital surveillance tool to maximize the recovery from this field. In this paper, we present the effectiveness of PNL tool specially RMT-I with production data over a period of 3 years (post Aug 2019). However, the results also include integration of other PNL dataset (RST & Raptor) acquired for reservoir surveillance activity and the challenges involved in interpreting the result of different PNL tool over time. In absence of RMT 3D tool, PNL is acquired as 1 Sigma up/down pass and 3 CO up passes at 1fpm-3fpm to address the uncertainty related to gas presence on C/O interpretation. Sigma measurement helped in identifying gas below packer or in the annulus behind pipe and helped in addressing the uncertainty related to gas presence on C/O interpretation. Secondly, RMT was planned in infill well post drill to determine the uncertainty between OH and Cased hole Oil saturation. The results agreed with production data and uncertainty in oil saturation estimation was minimized to 10-15% approximately. Several cases will be discussed in the paper to demonstrate the use of PNL logs for reservoir management.
- Geology > Geological Subdiscipline > Stratigraphy (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Sedimentary Geology (0.46)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation > NB-1 Well (0.98)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation > NB-1 Well (0.98)
- (2 more...)