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Results
Abstract This study aims at designing optimal crosshole seismic approach for CO2EOR (enhance oil recovery by CO2 injection) monitoring in Abu Dhabi. It is not easy to perform successful reservoir monitoring for carbonate reservoirs in the Middle East because rock properties may not change much associated with fluid replacement. We investigate advantage of newly available elastic full waveform inversion (FWI) for detection of CO2 flooded zones. To investigate advantage, applicability and future problem of time-lapse FWI for CO2EOR monitoring, we conducted rock physics study, elastic seismic simulation, and test application of FWI to synthetic data. We first made realistic velocity models based on Gassmann's equation and actual well logs obtained before and after CO2 injection at carbonate reservoirs in Abu Dhabi. The in-situ light oil at the target reservoirs was replaced by CO2 (Secondary mode CO2EOR). We prepared models with different width and thickness of CO2 flooded zones and analyzed detectability of seismic waveform change. We also conducted test application of elastic full waveform inversion to synthetic data for delineation of CO2 flooded zones. Results of the rock physics study show 1.6% decrease in P-wave velocity, little change in S-wave velocity and density associated with secondary mode CO2EOR. The small property changes are caused by the rigid rock frame and small density difference in light oil and supercritical CO2 at the reservoir condition. Next we performed synthetic seismic analysis based on the rock property models, available crosshole seismic source and realistic well distances. Because of the small property change, seismic traveltime difference and waveform change are quite small when well distance is 116ft. When well distance is 700 ft or greater, guided waves, or trapped energy inside low velocity layers can be observed; relatively large waveform change can be observed in the guided waves due to CO2 injection. Although guided waves have not been used for reservoir monitoring, they are sensitive to small Vp and thus can be an indicator of the CO2 flooding. The elastic FWI result for a model with well distance of 1160 ft demonstrated good representation of the differential Vp with vertical resolution of 20-30 ft and some horizontal resolution. Although we need further investigation on repeatability and signal transmittability using actual field data, our synthetic study indicates possibility of identifying layers with CO2 using guided waves and elastic FWI.
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract CO2-EOR is one of the proven enhanced oil recovery (EOR) techniques and has been used commercially. However, in field applications, unfavorable sweep efficiency is often reported. In order to improve the sweep efficiency of CO2 flooding, we investigated an applicability of CO2 micro bubbles. To evaluate the applicability of CO2 micro bubbles for CO2-EOR, we conducted core flooding experiments using CO2 micro bubbles and the results were compared with the normal CO2 flooding. Previous study confirmed the generation of CO2 micro bubbles by using a specially developed porous filter. Using this filter, core flooding experiments were conducted. During the experiment, flooding behavior was monitored by a medical X ray CT system, and recovered oil and water were collected to make a quantitative comparison with normal CO2 flooding. From the images taken by the medical X ray CT, we observed that CO2 micro bubbles flowed over both upper and lower parts of core samples, while normal CO2 flowed only upper part of core samples. As a result, a delay of CO2 break-through was confirmed in CO2 micro bubble flooding case. The time series of medical X ray CT images indicates improvement in sweep efficiency by using the CO2 micro bubbles. In addition to this, the material balance calculation during the core floodings revealed 3% of additional oil recovery compared to the normal CO2 flooding. From the experiments, differences in flooding behavior were clearly observed between the normal CO2 and the CO2 micro bubbles injection. We consider the differences would lead to the improvement of both vertical and areal sweep efficiencies. Although this technique is still in a stage of fundamental research, since the technique only requires the special filter and it is considered that it can be easily installed at the down hole, it may provide a novel option to improve the CO2-EOR performance.
- North America > United States (0.32)
- Asia > Japan (0.29)
A Novel Particle-Type Polymer and IOR/EOR Property Evaluation
Wu, Xingcai (Research Inst. of Petroleum Exploration and Development (RIPED) CNPC) | Xiong, Chunming (Research Inst. of Petroleum Exploration and Development (RIPED) CNPC) | Xu, Hanbing (Research Inst. of Petroleum Exploration and Development (RIPED) CNPC) | Zhang, Jian (China National Oil&Gas Exploration and Development Corporation (CNODC), CNPC International) | Lu, Changdong (Daqing Oilfield Company, CNPC) | Lu, Xiangguo (Northeast Petroleum University) | Li, Jinkui (Huabei Oilfield Company, CNPC) | Cao, Huiqing (Huabei Oilfield Company, CNPC) | Zhang, Na (RIPED) | Cui, Guoyou (Startwell Energy Co. Ltd) | Chen, JingJing (Startwell Energy Co. Ltd) | Ye, Yinzhu (RIPED) | Jia, Xu (RIPED) | Lv, Jing (RIPED) | Yang, Zhongjian (Qinghai Oilfield Company, CNPC)
Abstract Traditional polymer flooding technology is difficult to be used in high temperature and high salinity reservoirs, due to the property limitation of HPAM. It is the key of chemical flooding EOR to develop a new type of polymer, which can tolerate high temperature and high salinity and has high sweeping capacity. Through microemulsion / suspension polymerization technique, a new particle-type polymer is developed. The polymer size is in the range of 30 nm to 112 μm, and can be divided into three size sections: nanometer, micrometer, and submillimeter. The microscope is used to observe the appearance, and the apparent viscosity of the dispersion is also measured, with which the temperature and salinity resistance and water absorbing and expanding property of the new polymer can be evaluated. A 2.1 m long core model is made to test the in-depth migration of the polymer particle. The resistance factor and residual resistance facter evaluation method for traditional polymer is borrowed to test the retention property of the new polymer in cores. Parallel dual-pipe artificial and natual cores are used to simulate the IOR/EOR property of the new polymer for sand and carbonate reservoirs. The lab tests show the new polymer can tolerate high temperature, 120 °C, and high salinity, 200000 mg/L. The polymer particle can swell by 3-10 times in water by hydration, but do not change much in oil. The apparent viscosity of the new polymer liquid is 1-3cp, so it can be easily injected into deep reservoir. It can increase water flowing resistance, but not increase that of oil. When being used, the new polymer is a type of discontinuous liquid distributed with soft polymer particles, which is different from the traditional polymer, HPAM, which is a type of continuous viscous fluid. The IOR/EOR mechanism of the new polymer is different from that of the traditional polymer. As a type of dispersion displacing phase liquid, the new polymer can dynamically modify the permeable ability of different areas, by which the oil and water mobility can be modified effectively, achieving the aim of enhanced oil recovery. The studies preliminarily established the property evaluation method for particle-type polymer, and discovered the IOR/EOR mechanism of the new particle-type polymer. The pilot test conducted in a reservoir with high temperature, 120 °C, and high salinity, 14.9-21.7×10 mg/L, with Ca / Mg concentration of 2500 mg/L, obtained obvious oil rate increase and water cut decrease effect, and achieved technical and economical success.
- Asia > China > Qinghai > Qaidam Basin > Qinghai Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Asia > China > Hebei > Bohai Basin > Huabei Field (0.99)
The First Successful Chemical EOR Pilot in the UAE: One Spot Pilot in High Temperature, High Salinity Carbonate Reservoir
Al-Amrie, Omar (ADNOC) | Peltier, Sophie (ADNOC) | Pearce, Adrian (ADNOC) | Abu-Dhabi, Total (ADNOC) | Al-Yafei, Arafat (ADNOC) | Morel, Danielle (Total SA) | Bourrel, Maurice (Total SA) | Bursaux, Romain (Total SA) | Cordelier, Philippe (Total SA) | Jouenne, Stephane (Total SA) | Juilla, Hugo (Total SA) | Klimenko, Alexandra (Total SA) | Levitt, David (Total SA) | Nguyen, Michel (Total SA)
Abstract In 2014, Total performed a surfactant-polymer single-well pilot to test the effectiveness of a surfactant formulation developed in-house, and including a new proprietary class of surfactants with improved temperature- and salinity-tolerance characteristics. This paper unveils the results of this pilot which targeted a high temperature, high salinity carbonate reservoir. The operations were performed on an oil bearing reservoir of Lower Cretaceous age, in an offshore field operated by Total since 1974 and located 180 km offshore Abu Dhabi. Dedicated topsides were designed and installed for this EOR project. Extensive in-house laboratory studies were performed to select and synthesize the chemicals. Specific simulations, using laboratory results as input, were carried out to predict the pilot performance, design the Single Well Tracer Tests (SWTTs), and size the equipment. In this paper we will discuss the workflow used to select the most appropriate well and present the methods and results used to characterize the reservoir. Then we will relate it to the surfactant-polymer injection field operations. Finally the reservoir monitoring activities that were necessary to preserve reservoir integrity and demonstrate the pilot efficiency will be described. The strong decrease in remaining oil saturation measured after the chemical EOR pilot clearly proves the effectiveness of the chemicals synthesized by Total to mobilize the remaining immobile oil after water-flood. These positive outcomes change the perception of CEOR in hot, saline Middle-East carbonate reservoirs, and could be a "game changer".
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.93)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.93)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties. In this paper, a procedure to screen the best injectant for implementation of a successful gas injection pilot project is discussed. To determine the microscopic sweep efficiency, PVT experiments and coreflood tests are conducted. First, minimum miscibility pressure (MMP), oil solubility and IFT values are measured through PVT experiments, which is followed by unsteady-state coreflood experiments on 200 cm long cores to evaluate the sweep efficiency at miscible and immiscible conditions. Data from the experiments are used to evaluate oil recovery in a sector model extracted from the full field model. The sector model analysis for different injection scenarios provides sweep efficiency and guidelines for the implementation of the gas injection pilot project. The coreflood experiments show improvement in recovery in immiscible conditions due to oil swelling and reduction in IFT, while higher recovery is achieved in miscible conditions due to multiple-contact miscibility. Evaluation of the macroscopic sweep efficiency in the sector model highlights the issue of gas override, and suggests improving the sweep by gas enrichment, as well as water-alternating-gas injection (WAG).
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (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)
Abstract Polymer flooding is used as a secondary or tertiary recovery mechanism to enhance oil production and increase oil reserves. In such situations, part of the injected polymer will be back produced at the topsides at different ratios depending on the injection mode and along field life. The side effects of polymer flooding on the topsides process chain are identified as manageable trouble regarding oil/water separation, and major issues at the water treatment stage. The presence of polymer in the produced water increases the viscosity and the severity of the emulsion. Literature dealing with viscosified water has already highlighted decreases of efficiency of water treatment technologies such as hydrocyclones, flotation, generating inadequate water quality for produced water reinjection (PWRI). A common way to optimize flotation on field is to inject additives. But the polymer impedes the action of conventional chemicals used in O&G Production. Chemicals usually help to improve the water quality, regarding constraints of PWRI. This paper focuses on chemical approach along the separation and water treatment chain in case of back produced polymer. For this study, we used HPAM, a high molecular weight polyacrylamide commonly used in EOR. Previous works on conventional water treatment additives have shown a high consumption of chemical to clarify viscosified water, which is not economically practicable. Therefore, we proposed to explore another approach, first taking care of water quality upstream at the separation stage, then pursuing on chemical optimization at the water treatment stage. At first, a lab methodology for separation studies was developed to generate a thin emulsion with controlled degradation of the polymer, simulating the characteristics of the back produced viscosified water on field. A screening of demulsifiers was carried out on emulsion containing 10% oil and synthetic polymer back produced water (up to 500 ppm HPAM). These tests have shown that water quality can be improved at the separation stage, at conventional dosage at lab scale. The remaining oil in water for 10% initial oil, depending on the residence time, is maintained in the range of few tens to few hundreds ppm. Water treatment optimization reference case was then based on few hundreds ppm of remaining oil. For water treatment studies, oil in water emulsions were prepared by mixing oil with synthetic or real viscosified water (up to 500 ppm HPAM) with an ultra-turrax homogenizer. Different types of clarifiers ranging from 50 to 100 ppm were evaluated. These tests have shown that water quality can be improved using a combination of adequate additives. These bench lab results were confirmed on a lab conventional technology, and could be further evaluated in field trials for an integrated solution.
- North America > United States (1.00)
- Asia (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract Surfactant injection can be used as an EOR technique by either altering the wettability of reservoir and/or reducing IFT of water and oil. How to balance the functionality of wettability alteration and IFT reduction of a surfactant flooding process for oil wet carbonate reservoirs is still paradox for surfactant technology selection. In this study, the effects of IFT reduction and wettability alteration by surfactant on EOR for a carbonate reservoir were studied by using two kind surfactant systems individually. For IFT reduction surfactant, the surfactants which can reach IFT at different level and ultralow IFT were synthesized based on molecular design method by only changing the structure of surfactant and without any formulation process. Moreover, these surfactants are also has a little effect on wettability alteration proven by contact angle test. The surfactants for wettability alteration study are selected based on contact angle method and also on the principle of "less effect on IFT property". The static and dynamic imbibition tests are carried out to understand the contribution of wettability alteration and IFT reduction mechanism individually to enhance oil recovery, hence, the surfactant flooding technique for an oil wet carbonate reservoir could be optimized.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Quality Assurance and Control of Surfactants for Field Scale EOR Pilot Projects
Barnes, J. R. (Shell Global Solutions International B.V.) | van Batenburg, D. W. (Shell Global Solutions International B.V.) | Faber, M. J. (Shell Global Solutions International B.V.) | van Rijn, C. H. (Shell Global Solutions International B.V.) | Geib, S.. (Shell Global Solutions International B.V.) | van Kuijk, S. R. (Shell Global Solutions International B.V.) | Perez Regalado, D.. (Shell Global Solutions International B.V.) | King, T. E. (Shell Global Solutions (US) Inc.) | Doll, M. J. (Shell Global Solutions (US) Inc.) | Pretzer, L. E. (Shell Global Solutions (US) Inc.)
Abstract Alkaline Surfactant Polymer (ASP) flooding is an enhanced oil recovery (EOR) technique that involves the injection of a solution of surfactant, alkaline, and polymer into an oil reservoir to mobilize and produce the remaining oil. There are several pattern-flood pilots in progress or about to be executed to evaluate ASP at a scale relevant to commercial scale application. The quantities of surfactants needed for these pilots and potential future commercial scale applications are large (100s to 10,000s of ton) and necessitate large scale manufacture using existing processes and plants for the different manufacturing steps. These operate under slightly different process conditions than those used to make the smaller quantity (ca. 50 kg) of the reference blend, used to design the formulation in the laboratory. The upscaling of the surfactant production itself is an essential step to enable field scale implementation of ASP. In order to ensure and control the quality of the surfactants produced for pilots with Shell interests, a stage gated Quality Assurance/Control (QA/QC) programme was designed and executed. The application of the QA/QC process for a high and a low active matter surfactant blend concentrate (around 60% and 20% active, respectively) is used to illustrate the process. The early definition of the QA/QC programme provided a framework with clearly defined stages for upscaling from laboratory to large scale production. The definition of analytical and performance based laboratory experiments with up front defined specifications (minimum and maximum values) and repeatability allowed for clear, unambiguous decisions. Correlations between composition and performance that were developed based on pilot scale production were essential to assure the performance of the larger scale production. Core floods, used as the ultimate performance check, showed virtually identical performance for pilot scale prepared surfactants and surfactants from different large scale batches. The paper illustrates that consistent industrial scale production of surfactants for application in chemical EOR is feasible. To ensure the quality of such surfactants requires a detailed QA/QC programme. The successful execution of the QA/QC programme for the surfactants for the pattern pilots ensures that the produced large scale surfactant blend performs as the reference blend used to design the formulation.
- Asia (1.00)
- North America > United States > Illinois (0.28)
- Materials > Chemicals > Specialty Chemicals (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...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Foam displacement has been employed in several field pilots which report improvement in mobility control, sweep efficiency, delayed gas breakthrough and EOR. However, foam behavior in highly heterogeneous porous media in general and fractured reservoir in particular is not well understood. Effective application of foam for enhanced oil recovery requires a good understanding of physical displacement processes (e.g. adsorption, foam generation, foam decay) at the laboratory and field scale. This is particularly important for the more complex fractured carbonate reservoirs which host over half of the world's remaining conventional oil reserves. We investigate the effect of foam displacement in fractured carbonate reservoirs using numerical simulations tuned to experimental data to compare recovery for different injection strategies at different scales. In the experiments, high quality foam was generated by the injection of surfactant solution and N2 gas either in-situ or prior to injection. A mechanistic Lamella Density model was used to simulate core-scale laboratory experiments and history match the unknown foam parameters. We applied our understanding of foam displacement processes at the core scale to a reservoir model at the inter-well scale where additional heterogeneities were encountered. For this model we used a cross section of highly heterogeneous simulation model of a middle Jurassic carbonate ramp that is an analogue to the Arab D formation in Qatar. We used this model to test the effect of foam injection for different injection mechanisms, analyze the displacement processes, and compare the overall sweep and recovery. Foam injection showed very promising results by diverting the flow from the high permeability fractures to the matrix, allowing for a better sweep efficiency that lead to a noticeable increase in differential pressure. Pre-formed foam yielded a higher recovery (around 78% of OOIP) compared to the in-situ generated foam in the core samples. This might be due to the smooth nature of the fractures leading to fewer snap off sites for foam generation. Varying the foam injection strategies (i.e. pre-formed foam, co-injection, and SAG) resulted in at least a 12% change in recovery compared to conventional water flooding and water-alternating gas injection. Foam quality, foam stability and injection mechanism were all factors that controlled sweep efficiency. Our results illustrate how the laboratory-scale displacement mechanisms could operate on a larger (i.e. inter-well) scale where additional heterogeneities are encountered and the ratio of viscous to capillary and gravity forces changes. Our simulations also demonstrate that uncertainties in parameterizing foam models using experimental data from core floods translate into considerable uncertainties for predicting recovery at the field-scale. Still, foam can be an effective agent to increase oil recovery in fractured carbonate reservoirs by improving sweep efficiency and reducing gravity override.
- North America (0.94)
- Asia > Middle East > Qatar (0.24)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (1.00)
- Geology > Rock Type (0.68)
- North America > Canada > Alberta > Salt Creek Field > Amoco Et Al Salt Creek 4-12-76-10 Well (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Assessing CO2 EOR in different areas of a field with different rock and fluid properties requires proper dynamic reservoir modelling. Good SCAL data is a key input to the dynamic model. Consequently a comprehensive SCAL program was designed for a super giant carbonate reservoir, onshore Abu Dhabi, for modeling CO2 EOR process in secondary & tertiary conditions. A careful selection of the core material based on a Petrophysical Group (PG) review was performed to make the experiments representative of key areas of the field in which CO2 flood is planned or studied. Laboratory experiments were designed at full reservoir conditions with H2S oil bearing, and to assess possible impact of H2S on displacement efficiency. Water-oil relative permeability tests showed insignificant impact of H2S, compared with non-H2S tests on cores of different PG's. Injectivity issues and importance of brine composition on water mobility were identified. Trapped gas to water and oil were also mapped successfully. The comparative analysis of CO2 EOR flooding scenarios using long composite cores with continuous CO2 injection and CO2 WAG were also performed. They indicate higher displacement efficiency with continuous CO2 injection. Tests were also conducted on composites with non-H2S live crude, representative of reservoir zones with little or insignificant presence of H2S. This study indicated for the first time in the published literature, the impact of H2S in water-oil relative permeabilities of carbonates at full reservoir conditions. The gas process displacement efficiency tests also verified negligible impact of H2S (up to 12%) in CO2 EOR 1D core floods.
- 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 > Formation Evaluation & Management > Core analysis (1.00)
- (2 more...)