Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Laboratory Investigation of Factors Affecting CO2 Enhanced Oil and Gas Recovery
Liu, Keyu (CSIRO Earth Science and Resource Engineering and RIPED, PetroChina) | Clennell, Ben (CSIRO Earth Science and Resource Engineering) | Honari, Abdolvahab (The University of Western Australia) | Sayem, Taschfeen (The University of Western Australia) | Rashid, Abdul (CSIRO Earth Science and Resource Engineering) | Wei, Xiaofang (Research Institute of Petroleum Exploration and Development, PetroChina) | Saeedi, Ali (Curtin University of Technology)
Abstract A series of laboratory investigation on factors affecting Enhanced Oil and Gas Recovery and CO2 geo-sequestration were conducted. The coreflooding experiments were done using a relatively heavy crude oil (18& API), a number of brines of 0.18%-2.5% NaCl and varieties of cores with a range porosity and permeability from 15% and 17 mD to 19% and 330 mD under some typical reservoir pressure-temperature condition of 1164-3300 psi and 50-83 &C. Factors affecting CO2 enhanced oil and gas recovery including the effects of the petrophysical properties of the reservoir rocks, formation water salinity, reservoir pressure, the Minimum Miscibility Pressure (MMP), total volume (PV) injected and injection rate and gravity segregation. Excellent recovery factors in the range of 27%-34% Original Oil In Place (OOIP) and almost 100% gas recovery were achieved through immiscible and miscible CO2 flooding. Some of the coreflooding experiments were monitored with a medical CT in real time. The coreflooding experiments have shown that (1) reservoir petrophysical properties with permeability difference of up to an order of magnitude do not affect the CO2 EOR factor; (2) variable EOR can be achieved both at reservoir pressures below or above the CO2-oil MMP; (3) Incremental oil recovery is proportional to the pore volume (PV) of CO2 injected up to 3PV; (4) No significant additional recovery was observed beyond the MMP; (5) CO2-Water alternating gas (WAG) flooding can be quite effective in EOR in terms of the less amount of CO2 injected as compared to that for the single CO2-water flooding to achieve the same EOR; (6) there is no benefit to use low-salinity CO2 WAG flooding; (7) the optimum injection rate in the laboratory is around 1 cc/minute. These finding may provide some useful insight and guide for the field application of CO2 enhanced oil and gas recovery; (8) During enhanced gas recovery using supercritical CO2, gravity segregation may occur in some porous-permeable reservoir with denser supercritical CO2 preferentially enter through the bottom of the reservoir.
- North America > United States (0.79)
- Oceania > Australia > Western Australia (0.30)
- Oceania > Australia > Western Australia > Indian Ocean > Perth Basin > Abrolhos Basin > Block WA-325-P > Cliff Head Field (0.99)
- North America > Canada (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 2-4 July 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
- Europe (1.00)
- North America > United States > California > San Francisco County > San Francisco (0.28)
- Asia > Malaysia > Kuala Lumpur > Kuala Lumpur (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Illinois > Loudon Field (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Romashkinskoye Field (0.99)
- Europe > Germany > Knesebeck Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 2-4 July 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Chemical injection in enhanced oil recovery (EOR) projects is a complex process because it involves multiple chemicals with complex fluids. Costs for even a small-scale pilot test could be up in the millions of US dollars (USD) and large-scale fieldwide expansion would be in the 100s of millions USD for onshore projects. Costs for offshore projects would increase by multiple folds compared to onshore projects with comparable sizes. This paper discusses (1) conventional designs for small-or large-scale injection facilities, (2) recent improvements in conventional designs, and (3) new concepts in chemical injection facility designs that can improve the quality, lower the cost, and reduce the lead time in the implementation of chemical EOR (CEOR) projects. Introduction Major CEOR processes can be classified into two categories: polymer applications and surfactant processes. Polymer applications include polymer flooding (PF), and polymer gels for profile modification and water shut-off.
- North America > United States (1.00)
- Asia > China (0.69)
- Asia > Malaysia > Kuala Lumpur > Kuala Lumpur (0.24)
- 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)
- (4 more...)
Abstract In CO2 projects for enhanced oil recovery (EOR) a critical factor is possible early CO2 breakthrough and consequently poor sweep efficiency. Injection of foam can block and divert CO2 which may improve sweep efficiency. Large changes in physical properties of CO2 with temperature and pressure might affect CO2-foam performance under various reservoir conditions. Recently, we have focused on understanding supercritical CO2-foam properties and this paper describes the importance of supercritical CO2 density on CO2-foam performance in outcrop Berea sandstone core material. Foam flooding experiments were conducted in sandstone core material at different pressures from 30 to 280 bar and at temperatures of 50 and 90°C using an AOSC14/16 surfactant. Results showed high foam strengths at low CO2 density. In fact, the strongest supercritical CO2-foam was generated at the lowest supercritical CO2 density tested, quite comparable to foam strength obtained with gaseous CO2. Only reduced foam strengths were found with dense supercritical CO2 (MRF 3-11). Foam generation was studied with both equilibrated and non-equilibrated fluids. Previously, we showed that CO2-foam stability and blocking ability were strongly reduced when mass transfer occured. In this study delay in foam strength build-up was observed with non-equilibrated fluids. In addition, visual observations of the foam texture indicated larger bubbles. Compared to N2-foams at similar conditions CO2-foams were weaker and showed coarser foam structure.
- Geology > Mineral > Silicate (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
The First Application of IWAG Surveillance Program with Integrated Operation (IO) for Dulang Field Offshore Malaysia
W. Daud, W. Ata (Exploration & Production Technology Centre, PETRONAS) | Sedaralit, M. F. (Exploration & Production Technology Centre, PETRONAS) | Wong, Fadhli (Exploration & Production Technology Centre, PETRONAS) | Affendi, Amierul (Exploration & Production Technology Centre, PETRONAS)
Abstract With declining oil production, the Exploration & Production companies are in search of applying innovative methodologies to improve recovery factors from existing fields. Immiscible Water Alternating Gas (IWAG) has been identified as one of the enhanced-oil recovery techniques for offshore Dulang oil field in Malaysia. The field redevelopment FDP study was initiated in 2007 to evaluate the optimum recovery scheme to increase oil production from all reservoirs in Dulang field. Results from the simulation study indicated that the major reservoirs will benefit from IWAG injection, with ultimate recovery as high as 50% in some reservoirs. Phase 1 of IWAG injection was started in April 2012 Prior to IWAG field implementation, extensive surveillance program was developed to ensure requires data is captured for monitoring the success of the project and provide a feedback for improvement. This paper explores the selection of tools and testing programs adopted in surveillance program which include Integrated Operation (IO) for IWAG injection in the Dulang field. The new proposed surveillance program is expected to improve water flood and IWAG monitoring; Monitors stable front (water or gas) with high sweep efficiency to push oil to producer Monitors and forecasts displaced reservoir hydrocarbon and water volumes Enables to see and understand the status-quo of WF/WAG performance in each block and reservoir The new IWAG surveillance program with the IO system will enable the surveillance team to move from reactive to a proactive asset management system. Real time data will enable engineers to know the status of injection facilities, well status and rate and the performance of IWAG EOR in Dulang.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-267-P > Greater Gorgon Field > Jansz-Io Field (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 6 > Dulang Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (0.90)
- Information Technology > Security & Privacy (1.00)
- Information Technology > Architecture > Real Time Systems (0.90)
Performance Review of Polymer Flooding in a Major Brown Oil Field of Sultanate of Oman
Thakuria, Chandan (Petroleum Development of Oman) | Al-Amri, Mohsin Saud (Petroleum Development of Oman) | Al-Saqri, Kawthar Ahmed (Petroleum Development of Oman) | Jaspers, Henri F (Petroleum Development of Oman) | Al-Hashmi, Khalid Hamad (Petroleum Development of Oman) | Zuhaimi, Khalid (Petroleum Development of Oman)
Abstract The first field scale Polymer flood project in the Middle East region is being implemented in an oil field of Sultanate of Oman from early 2010. The oil field discussed here containing viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding. This field scales Polymer flood project comprising 27 patterns as Phase-1 covers about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in all these 27 injectors. Further extension in phases to full field polymer flooding is under evaluation. Till now this Polymer flood project has successfully completed 3 years of good performance contributing to significant oil gain. This paper describes briefly about the principles involved in polymer flooding, planning of this polymer flood project, field implementation and field examples of polymer response. In addition, a few practical aspects of managing key issues in polymer flooding like- fracture growth in injectors, shear degradation of polymer solution, pattern conformance and back produced polymer has been covered in this paper.
- Asia > Middle East > Oman (1.00)
- North America > United States > Texas > Terry County (0.50)
- North America > United States > Texas > Gaines County (0.50)
- Europe > United Kingdom > North Sea > Southern North Sea (0.50)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Al Khlata Formation (0.99)
- Asia > Middle East > Oman > Central Oman > South Oman Salt Basin > Mahwi Formation (0.99)
Abstract In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 10m (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 10m (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible. A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations. Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells. The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
- North America > Canada > Alberta > Etzikom Field > 1117695 Etz 11-13-6-8 Well (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract Immiscible WAG (IWAG) processes, although proven quite useful in maintaining pressure in low permeability reservoirs, has the inherent drawback of leaving high residual oil saturation (Sor) behind the flood front. Often, dependent on the reservoir characteristics, the oil volume which is left behind by a secondary IWAG process can be of significant value and requires investigating tertiary EOR processes that could economically produce it. This case study discusses the approach taken to mature an EOR opportunity in a giant onshore carbonate reservoir currently being developed with IWAG injection. A plan was put in place to assess the suitability of prospective EOR processes in the subject reservoir. This commenced with a detailed PVT lab study which involved specially designed EOR tests such as swelling, slimtube, forward contact, backward contact, equiphase and asphaltene deposition. The experimental data was used to develop an equation of state model (EOS) that is able to describe the reservoir fluid behavior. Next, analytical methods were used to screen out the EOR processes found most promising. The EOR processes were screened based on the performance indicators estimated using classical reservoir engineering techniques, empirical methods, experience and judgment. The favourable results for the CO2 injection, both from the PVT experiments and the analytical screening led to the design of 1D coreflood experiments on composite cores at full reservoir conditions. Comparison of the different displacement tests showed CO2-WAG to be highly efficient recovery mechanism with 93% of the HCPV recovery potential. The PVT experiments and the coreflood injection tests, within their experimental limitations provided recovery profiles and CO2 injection characteristics to validate model predictions on a microscopic scale, and thus enhanced confidence in full field development studies based on the underlying reservoir simulation models. The proposed CO2-EOR strategy will help reduce the Sor significantly and hence improve Ultimate Recovery (UR). A field pilot is being considered to evaluate the CO2 injection recovery process optimally.
- Asia > Middle East > UAE (0.46)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- 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)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract CO2 is injected into mature reservoirs for both sequestration and EOR. The effect of CO2 flooding on asphaltene stability has been extensively addressed in literature. In contrast, asphaltene / water interaction has not received much attention in literature. The objective of the paper is to address the asphaltenic oil recovery by water alternating CO2 injection (WACO2) and asphaltene/ions interaction. Different water compositions, such as synthetic seawater (SSW) and low salinity water (LSW), Na2SO4, MgCl2 ions, and ion free water (DW), are used. SO4 and Mg ions were selected based on previous work on their interaction with chalk minerals and modifying the surfaces to more water wet. CO2 is injected in miscible mode within the WACO2 recovery process. For simplicity outcrop cores and model oil were used. Model oil consists of n-C10, 0.35wt% asphaltene (extracted from a Middle East crude oil) and natural surfactant (stearic acid, SA). The effects of water injection rates were also investigatd to address the oil recovery efficiency in the cores and assess the water/oil/rock interaction as a function of injection rates. Imbibition process with various water compositions was tested for cores unflooded and flooded with CO2. This is to address the effect of CO2 on the fluids interaction. It was shown that higher oil recovery was obtained when Mg solution was used as imbibing fluid after CO2 flooding compared to SO4 solution. The opposite was observed without the CO2 flooding where higher recovery was obtained when Na2SO4 solution was used as an imbibing solution compared to that with MgCl2 as imbibing fluid.
- Geology > Mineral > Sulfate (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
Abstract Angsi field is slated to be the first in the world for Alkaline-Surfactant and Polymer (ASP) chemical flooding via a floating structure in an offshore environment. The chemical flooding will be for 3 years with 6 months of low salinity water pre-flush injection prior to chemical injection to condition the reservoir, and 6 months of treated seawater with polymer injection as post-flush activity. The chemical flooding will be conducted via injection of treated and partially desalinated seawater mixed with ASP chemicals produced from the floater which is tie-in to the existing Angsi water injection pipeline network (Figure 1.0). Angsi reservoirs will experience three (3) different salinity range exposures with two (2) as invading fluids with effects of chemical cocktail, wettability and fluid distribution. One of the main challenges for ASP flooding in an offshore environment is handling the chemical residuals breakthrough in produced water causing the water unable to be disposed overboard. To overcome this problem and to eliminate environmental pollution, a full scale Produced Water Re-Injection (PWRI) system with full integration to existing Angsi Produced Water Treatment (PWT) system should be adopted to meet the new water reinjection specifications. Since the PWRI water will be commingled with treated and partially desalinated seawater mixed with ASP chemicals from the floater, it is paramount to predict the range of salinity of the produced water over time to help to design the PWRI and Floater's water treatment system to achieve the final water quality and optimum salinity required for an effective ASP cocktail for re-injection. This paper will summarise the PWRI design and operation philosophy coupled with subsurface studies to predict salinity profiles for the produced water.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Asia > Malaysia > Terengganu > South China Sea (0.25)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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 > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 305 > Angsi Field (0.99)
- (3 more...)