Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Energy demand has been escalating and is predicted to increase further in the coming decades. The dialogue on global climate change has the world abuzz on the primary green house gas, carbon dioxide. Both of these factors have created a perfect storm for the use of carbon dioxide for enhanced oil recovery. The petroleum industry is ideally suited for disposing of this green house gas. Each oil company (and others) has therefore stepped up its efforts in carbon dioxide utilization, either for EOR or sequestration. The injection of CO2 into a reservoir is not new. Indeed CO2 injection has established itself as a very efficient mechanism for increasing oil recovery. To design a CO2-EOR or CO2 sequestration project, one requires a large set of appropriate experimental data for a given reservoir/fluid system. Where does one start? Even if the data have to be generated in a service lab, a good design requires some thought and effort. A search of the literature reveals no best practices for generating this dataset. This paper presents a comprehensive experimental design for conducting a CO2 laboratory study. The essential components of a laboratory study for CO2 injection include measuring fluid-fluid interactions and fluid-rock interactions. Fluid-fluid studies include miscible displacement tests, measurement of minimum miscibility pressures, fluid properties of CO2-oil or CO2-brine mixtures including viscosity and density, asphaltene precipitation, and swelling. Fluid-rock interaction studies typically include coreflooding tests for determining the oil recovery potential, three-phase relative permeability, critical gas saturation, gas trapping and wettability changes. Each of these sets of experiments will be described in light of their best practice. The ultimate goal is to establish a procedure for generating a reliable and accurate dataset.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.94)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Geology > Geological Subdiscipline (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Novel Method for Characterizing Single-phase Polymer Flooding
Sun, Wenjie (Shengli Oilfield, SINOPEC) | Peking, U.. (Shengli Oilfield, SINOPEC) | Li, Fen (Shengli Oilfield, SINOPEC) | Qu, Yantao (Shengli Oilfield, SINOPEC) | Yang, Yaozhong (Shengli Oilfield, SINOPEC) | Li, Kewen (China U. of Geosciences/Stanford U.)
Abstract Polymer flooding has been used to enhance oil production and reduce water cut for a long time. However there are still many fundamental challenges in characterizing the multi-phase fluid flow, even the single-phase fluid flow, associated with polymer flooding. For example, it is difficult to measure and calculate two-phase polymer solution/oil relative permeability. One of the difficulties comes from the non-Newtonian and time-dependent properties of polymer solutions; another comes from the change in absolute permeability caused by the adsorption of polymer on rock surfaces. Almost all of the methods for computing relative permeability are based on the assumption that the absolute permeability is constant. It will be helpful to further understand the mechanisms and develop more reliable methods for calculating two-phase polymer solution/oil relative permeability by investigating the single-phase polymer flooding more profoundly. In this study, a new method has been developed to calculate the pseudo permeability during single-phase polymer flooding. The non-Newtonian property of the polymer solutions was considered in the proposed method. A series of polymer flooding experiments using different concentrations of polymers were designed and conducted to study the single-phase flow of polymer solution in rocks with different permeabilities. The values of the pseudo permeability of single-phase polymer flooding were then calculated using the new method. It has been found that the relationships between the pseudo permeability and the reciprocal of shear rate were linear. The pseudo polymer flooding permeability extrapolated at the infinite shear rate was close to the brine flush permeability after polymer injections in most of the cases.
- Asia > China (0.95)
- North America > United States (0.68)
- Research Report > New Finding (0.89)
- Overview > Innovation (0.54)
- Asia > China > Shandong > North China Basin > Shengli 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)
Abstract HPAI in Light oil reservoirs have gained a success nowadays in the field. Air injection in light oil is decided on the basis of in which phase of the life reservoir stands. The main aim of this EOR method is to strip out the Lighter Hydrocarbons from the residual Heavy Fractions and also to act as a pressurizing agent as from conventional heavy oil reservoirs to reduce the viscosity and removing the residual oil saturation. The factors affecting the HPAI are Geology and the Geological structure and the reaction kinetics parameters like reaction frequency, enthalpy, activation energy and the mode of reaction i.e. Low Temperature Oxidation (LTO) and High Temperature Oxidation (HTO). In this paper, the laboratory procedures, for the Air injections have been calculated i.e. the velocity of the combustion front, temperature profiles and the ignition time of the initiation of reaction. Simulation of combustion tube experiment has been carried out and expanded to the block model in CMG STARS. The tuning of the reaction parameters is to generate the temperature profile of the twelve zones of the combustion tube experiment. History matching with the data generated in simulation and the outcomes of the laboratory experiment is performed. The block model with five spot inverted pattern predicts the variation of oil saturation, temperature, oil cut, water cut, cumulative fluid rates with time. The conclusion from this simulation is the feasibility of High Pressure Air injection processes in Light Oil Reservoir and predicting the future performance in the reservoir. The results from this simulation were that the clay particles affect the reaction kinetics in the Light Oil and the increment in the recovery is about 20 % because of HPAI.
- Asia (1.00)
- North America > United States > Oklahoma (0.28)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type (0.93)
Miscible Gas Injection and Asphaltene Flow Assurance Fluid Characterization: A Laboratory Case Study for a Black Oil Reservoir
Memon, Afzal (Schlumberger) | Qassim, Bashar (Schlumberger) | Al-Ajmi, Moudi (Kuwait Oil Company) | Kumar Tharanivasan, Asok (Schlumberger) | Gao, Jinglin (Schlumberger) | Ratulowski, John (Schlumberger) | Al-Otaibi, Basel (Kuwait Oil Company) | Khan, Rizwan Ahmed (Schlumberger)
Abstract Miscible gas flooding is the most commonly used enhanced oil recovery (EOR) method. One of the most important experimental parameters for miscible gas injection is minimum miscibility pressure (MMP). Many times, the MMP of a system can be very high. Instead of raising the pressure to achieve miscibility, injection gas may be enriched with intermediate components. The enrichment level at which the gas-oil system becomes miscible is called minimum miscibility enrichment (MME). Regardless of the values of MMP and MME, gas injected into a reservoir will most likely induce asphaltene precipitation, which may potentially cause formation damage and reduce flow in the production tubing. In this paper, reservoir fluid from a Kuwait reservoir was analyzed to check for the feasibility of miscible gas injection. First, a series experiments were conducted to measure MMP with various gases using different techniques and MME testing with slimtube experiments. Moreover, the benefits, disadvantages, and applicability of each experimental method for EOR testing with gas injections were compared. Second, asphaltene precipitation upon gas injection was investigated in detail by measuring the precipitation onset conditions. Asphaltene precipitation onset was measured using a near infrared (NIR) light-scattering technique and a high-pressure microscope system to analyze the measured data. Finally, the asphaltene precipitation locus on a pressure-temperature (PT) diagram and the amount of precipitation were modeled for the reservoir fluid with different concentrations of injection gas. The modeling was carried out using a composition-based cubic equation-of-state approach. The experimental and modeling results indicated that an increase in concentration of injection gas appears to aggravate asphaltene precipitation.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (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)
A Cyclic-Steam Injection in Fuyv Reservoir, Daqing
Li, Xiuluan (Petrochina Company Limited) | Wu, Yongbin (Petrochina Company Limited) | Zhao, Xin (Daqing Oilfield Company) | Gao, Panqing (University of Wyoming) | Qin, Qingsong (Huanxiling Plant of Liaohe Oilfield Company) | Yu, Ming (6th Plant of Daqing Oilfield Company)
Abstract Cyclic Steam Stimulation has already been proved as an important thermal recovery technology in the development of heavy oil reservoirs, which accounts for more than 60% percent of the annual heavy oil production in China. While with the increase of stimulation cycles, the cyclic production performance becomes poor because of the reservoir heterogeneity, high insitu oil viscosity and formation rhythms, which result in steam channeling along high permeability zones, limited heated radius and steam overriding. Many previous researches[1-5] have proved that nitrogen foam assisted steam injection can increase the sweep efficiency, supply formation energy and control steam mobility, and thus increase oil recovery of cyclic steam injection. However, research on the screening of optimum foam for a particular reservoir is important to enhance the field production performance. This paper is to present a detailed process of the planning, implementation, and evaluation of a field trial of N2-foam assisted cyclic steam stimulation at the Fuyv heavy oil reservoir in Daqing oilfield. At present, Fuyv heavy oil reservoir has experienced 6-7 cycles of CSS in average. Because of the high oil viscosity (viso. @ reservoir: 3200mPa.s), thick oil formation (avg.: 40m) and high heterogeneity (permeability range: 61.5 to 3650 mD), the injected steam advances suddenly along high permeability positions, resulting in serious channeling and low oil recovery factor. Therefore, in view of the geologic characteristics and fluid properties, 4 sets of N2-foam system are screened by static tests of foam adaptability to temperature, salinity, and different oil samples, and then operating parameters including foam concentration, injection rate and injection pattern are optimized by numerical simulation based on the detailed geologic modeling and history match for the target area. According to the operation strategy of N2-foam assisted cyclic steam stimulation acquired by evaluation experiments and numerical simulation, the N2-foam assisted cyclic steam stimulation are conducted in two wells successively and the pilot injection has foreseeable results in enhancing oil recovery factor.
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe 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)
Studies On Nitrogen Foam Flooding For Conglomerate Reservoir
Hou, Qingfeng (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration & Development, CNPC) | Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration & Development, CNPC) | Luo, Yousong (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration & Development, CNPC) | Weng, Rui (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration & Development, CNPC) | Guoqing, Jian (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration & Development, CNPC)
Abstract Keshang formation in Karamay oil field belongs to typical conglomerate reservoirs. It is characterized by high water cut, poor sweep efficiency, high heterogeneity and inefficient oil recovery during the end-period of water flooding. The selection of EOR technique is very important for future development of such reservoirs. Foam flooding can improve macroscopic sweep efficiency, which may increase oil recovery for highly heterogeneous reservoirs particularly. In this study, systematic laboratory studies on foam flooding for Keshang formation have been performed. Both the foamability and stability are the key factors to ensure high incremental oil recovery. The nitrogen foam formulas were optimized which had good performance of foamability and stability. The operating parameters including foam injection modes and gas liquid ratio were investigated by core flooding experiments at reservoir conditions. The results show that: 1. Injection mode is an important factor and the direct injection of foam is better than co-injection of gas and solution obviously. 2. The gas liquid ratio is another important parameter. The optimized gas liquid ratio was proposed as 3:1-5:1 for direct injection mode. EOR effect evaluation indicated that foam flooding could contribute 40.00% OOIP recovery even if the recovery after water flooding was 41.50% under good operating protocols. The remarkable increasing of injection pressure during the foam flooding indicated that nitrogen foam flooding had excellent profile control ability. Foam flooding integrates both properties of gas injection technique and chemical flooding. It is a candidate EOR method for highly heterogeneous conglomerate reservoirs.
- 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)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (13 more...)
- 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)
Colloidal-suspension Flow in Rocks: A New Mathematical Model, Laboratory Study, IOR
Aji, K.. (Australian School of Petroleum, The University of Adelaide) | McLindin, C.. (Australian School of Petroleum, The University of Adelaide) | Saha, A.. (Australian School of Petroleum, The University of Adelaide) | Le, K.. (Australian School of Petroleum, The University of Adelaide) | You, Z.. (Australian School of Petroleum, The University of Adelaide) | Badalyan, A.. (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, P.. (Australian School of Petroleum, The University of Adelaide)
Abstract A new analytical model for deep bed filtration of colloidal/suspension transport under size exclusion particle capture is developed and validated. The laboratory tests on suspension flow in engineered porous media, which simulate the injection of colloidal and particle suspensions in rocks, have been carried out. The model was successfully matched with the laboratory coreflood results, predicting particle breakthrough and stabilised concentration. Compared to the previous population balance model, the present one provides a better prediction of the normalised particle concentration versus jamming ratio. The sensitivity analysis shows that among the three parameters: the mean pore radius, the standard deviation and the inter-chamber distance, the first one has the largest effect on the outlet concentration.
- 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 > Formation Evaluation & Management (1.00)
- Well Drilling > Drilling Fluids and Materials (0.86)
Water-Based Enhanced Oil Recovery EOR by "Smart Water" in Carbonate Reservoirs
Fathi, S. Jafar (Core Energy AS, Oslo Norway and Department of Petroleum Technology, University of Stavanger) | Austad, Tor (Department of Petroleum Technology, University of Stavanger) | Strand, Skule (Department of Petroleum Technology, University of Stavanger)
Abstract Water chemistry has a profound effect on the stability of the water film and desorption of organic oil components from the mineral surfaces in a waterโbased enhanced oil recovery (EOR) process. By knowing the chemical mechanism for the symbiotic interaction between the active ions in seawater; Ca, Mg, and SO4, "Smart Water" can be designed and optimized in terms of salinity and ionic composition as an EORโfluid. In the present study, the efficiency of "Smart Water" on oil recovery in carbonate rock is summarized and discussed in the temperature range of 70โ120 ยฐC. By removing nonโactive salt, NaCl, from the composition of the injected seawater, the oil recovery by spontaneous imbibition was improved by about 5โ10% of OOIP compared to seawater. On the other hand, an increase in the concentration of NaCl in the imbibing fluid resulted in reduced oil recovery of 5% of OOIP. A systematic decrease in oil recovery was observed when diluting seawater with distilled water to obtain a low salinity brine, 1000โ2000 ppm. The decrease in the oil recovery was attributed to the reduced concentration of the active ions. When seawater depleted in NaCl was spiked by SO4, the oil recovery increased by about 5 to 18% of OOIP compared to seawater depleted in NaCl. The amount of Ca in the seawater depleted in NaCl had no significant effect on the oil recovery at low temperatures, โค100 ยฐC, but improvements were observed at higher temperatures. The wetting condition after spontaneous imbibition of seawater, seawater depleted in NaCl, and seawater depleted in NaCl spiked with sulfate was monitored using a chromatographic wettability test, and it showed an increasing order in the waterโwet fraction, in line with increased oil recovery. The results were discussed in terms of the previously suggested mechanism and the effect of the ionic double layer at the rockโbrine interface.
- Europe (0.95)
- North America > United States (0.93)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
EOR Field Management Through Well-Planned Surveillance
Zwaan, Marcel (Shell) | Hartmans, Rob (Shell) | Schoofs, Stan (Shell) | de Zwart, Bert Rik (Shell) | Rocco, Guillermo (Shell) | Adawi, Rashid (Shell) | Saadi, Faisal (Shell) | Shuaili, Khalfan (Shell) | Lopez, Jorge (Shell) | Ita, Joel (Shell) | LโHomme, Tanguy (Shell) | Sorop, Tibi (Shell) | Qiu, Yuan (Shell) | van den Hoek, Paul (Shell) | al Kindy, Fahad (Shell) | Busaidi, Said (Shell) | Fraser, John (Shell)
Abstract PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. However, the interpretation of this advanced surveillance data and integration into well and reservoir management workflows is still challenging. This paper describes the results of the integrated workflows for the interpretation, modeling and integration of surveillance data in four EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through time lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging. This paper shows that the surveillance has contributed to the understanding of recovery mechanism in a pattern steam flood, it has supported decisions well-recompletions and work-overs and it has supported decisions on injection rates and surveillance planning in the chemical flood project.
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 6 > Dulang Field (0.99)
- Asia > Malaysia > South China Sea > Malay Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Abstract The Mukhaizna field is a giant heavy oil field under steamflood for the past four years. A sector with NW-SE elongate low relief anticlinal structure from a complex full-field geological model with 200,000,000+ cells of channelized braided-fluvial sandstone deposition was upscaled to a dynamic model with 400,000+ cells. This sector model approximately 15% of the field production area, from the crestal part of the field comprises 87 producers and 78 Limed Entry Perforated injectors with several years of production and steam injection history. A precursor for almost every reliable production forecast is a good history matched simulation model which becomes the cornerstone to optimize the decision making process. This paper describes an integrated and comprehensive simulation modeling workflow which was implemented to incorporate geological, petrophysical and dynamic uncertainties in a systematic way to calibrate the simulation model. Sensitivity analysis was performed to identify key static and dynamic input parameters. A computer assisted optimizer which applies experimental design and Tabu search techniques was used to test nonlinear and interaction effects of about 25 input parameters. This could be practically impossible using traditional sequentially modifying one-variable-at-a-time approach which always is cumbersome and may skew into an apparent solution even when none exists. During the iterative history matching process, uncertainties related to input parameters were constrained and modified from time to time to get an optimal solution. In addition to history matching 165 production/injection wells and 35 wells with pressure data, an attempt was made to match temperatures in 13 observation wells as well as heat breakthroughs in 70 patterns. The use of advanced techniques allowed us to minimize number of simulation runs and significantly reduced time to complete model calibration in less than couple of months which could traditionally take more than a year and still be limited in efficiently testing all possible combinations of input parameters.
- Geology > Rock Type (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.66)
- Asia > Middle East > Qatar > Khuff Formation (0.99)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Gharif Formation (0.99)
- Asia > Middle East > Oman > South Oman > South Oman Salt Basin > Al Khlata Formation (0.99)
- Asia > Middle East > Oman > Al Wusta Governorate > South Oman Salt Basin > Mukhaizna Field (0.99)