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Collaborating Authors
Results
CCUS in China: Challenges and Opportunities
Guo, Hu (China University of Petroleum-Beijing) | Lyu, Xiuqin (Sinopec Northwest Oil Field Company) | Meng, En (China University of Petroleum-Beijing) | Xu, Yang (China National Logging Company Ltd) | Zhang, Menghao (China University of Petroleum-Beijing) | Fu, Hongtao (China University of Petroleum-Beijing) | Zhang, Yuxuan (China University of Petroleum-Beijing) | Song, Kaoping (China University of Petroleum-Beijing)
Abstract CO2 emission was the major cause that accounted for the global warming and climate chance. How to reduce CO2 footprint to stop or slow down the global warming has been hot topic. As a developing country, China has become the largest CO2 emission nation in the world during the industrialization process to develop economy, although the CO2 emission intensity has been reduced significantly compared to previous stage. China has promised and succeeded to keep the promise reduce carbon intensity to meet the requirement of Paris Agreement. To meet the promise to attain carbon peak emission in 2030 and carbon neutrality in 2060 (CPCN), carbon capture, utilization and storage (CCUS) is an important and necessary step. Considering the high cost, high energy intensity and complex technology integrated optimization add uncertainties of CCS, utilization of captured CO2 can be of vital importance. One of the most attractive CCUS in China is CO2 enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 may be one the best CCUS ways for China for the following three reasons. First, it can meet the increasing oil demand while reducing the carbon intensive coal. Second, around 66 CO2 EOR field tests have been conducted in China and experiences have ben gained. Finally, CO2 EOR in the USA was a proven technology which can increase oil production significantly and stably. Latest CCUS technology progress in China was reviewed. As of July 2021, 49 projects were carried out or under construction. Net CO2 avoided costs from 39 projects varied from 120 to 730 CNY/ ton CO2 (18.5-112.3 USD/ ton CO2). Although CCUS technology development in China was significant, the gap between global leading levels are obvious. Current challenges of CCS EOR include high CO2 capture cost, small scale, low incremental oil recovery, long-time huge capital input. The costs can be significantly reduced when the scale was enlarged to a commercial scale and transportation costs were further reduced by either pipelines or trains. CO2 transportation with well-distributed high-speed rail in China may be a feasible choice in future. If the CO2 EOR in China develops with the same speed as the USA, CO2 used for EOR in 2050 can be as high as 87.27 million tons. CO2 used for CO2 EOR in 2050 can account for 17% to 44% of the CO2 emission. CCS EOR in China will provid both domestic and international companies with good opportunities.
- Asia > China (1.00)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.31)
- North America > United States > Texas > Permian Basin > Central Basin > Wasson Field > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Wasson Field > Wichita Albany Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Northwest Field (0.99)
- (8 more...)
Abstract Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drop from the injection well to the polymer front may act as a pressure barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity (and even sweep efficiency in some cases). This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Both analytical and numerical methods are used to address this issue. We examine the relevance of the pressure barrier concept for a wide variety of circumstances, including oil viscosities ranging from 10-cp (like at Daqing, China) to 1650-cp (like at Pelican Lake, Alberta), vertical wells (like at Tambaredjo, Suriname) versus horizontal wells (like at Milne Point, Alaska), single versus multiple layered reservoirs, permeability contrast, and with versus with crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multi-zoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors (like fracture extension) intervene. For multi-zoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. The relevance of our findings is applied to operations for several existing polymer floods. This work is particularly relevant to viscous-oil reservoirs (like Pelican Lake and others) where the injected polymer viscosities are substantially lower than the oil viscosity
- North America > Canada > Alberta (0.89)
- North America > United States > Texas (0.68)
- Asia > China > Heilongjiang Province > Daqing (0.26)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- (5 more...)
Conformance Improvement in Fractured Tight Reservoirs Using a Mechanically Robust and Eco-Friendly Particle Gel PG
Wei, Bing (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Tian, Qingtao (Southwest Petroleum University) | Xu, Xingguang (China University of Geosciences) | Wang, Lele (Southwest Petroleum University) | Tang, Jinyu (United Arab Emirates University) | Lu, Jun (The University of Tulsa)
Abstract Conformance control in tight reservoirs remains challenging largely because of the drastic permeability contrast between fracture and matrix. Thus, reliable, durable and effective conformance improvement methods are urgently needed to increase the success of EOR plays in tight reservoirs. In this work, we rationally designed and prepared a mechanically robust and eco-friendly nanocellulose-engineered particle gel (referred to NPG) toward this application due to the superior stability. The impacts of superficial velocity, NPG concentration and particle/fracture ratio on the transport behavior in fracture were thoroughly investigated. We demonstrated that the mechanical properties of NPG such as strength, elasticity, toughness and tensile strain were substantially promoted as a result of the interpenetrated nanocellulose. During NPG passing through fracture model, it produced a noticeably greater flow resistance in comparison with the control sample (nanocellulose-free), suggesting the better capacity in improving the conformance of fractured core. It was found that the generated pressure drop (ฮP) was more dependent on the particle/fracture ratio and NPG concentration.
- North America > United States (1.00)
- Asia > China (0.68)
- Asia > Middle East > UAE (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Polymer Containing Produced Fluid Treatment for Re-Injection: Lab Development to Field Deployment
Pinnawala, Gayani Wasana (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Subrahmanyan, Sumitra (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Alexis, Dennis Arun (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Palayangoda, Sujeewa Senarath (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Linnemeyer, Harold (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Matovic, Gojko (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Kim, Do Hoon (Chevron Oronite a Division of Chevron U.S.A. Inc.) | Theriot, Timothy (Chevron Oronite a Division of Chevron U.S.A. Inc.) | Malik, Taimur (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Dwarakanath, Varadarajan (Chevron Technical Center, a Division of Chevron U.S.A. Inc)
Abstract Chemical Enhanced Oil Recovery operations involve injecting polymer and surfactants for enhanced recovery. Some of the polymer and surfactant are produced in the form of emulsions. The emulsions need to be treated to recover the oil and reuse water for mixing new polymer for injection. New treatment methods are required to effectively break these emulsions. While chemical treatment and other methods are effective in breaking emulsions formed by electric submersible pumps (ESP's), these methods are not successful in breaking emulsions formed by injected chemicals for CEOR. Reuse of produced water is important in off-shore as well as some on-shore fields. Produced water re-injection requires mixing of fresh polymer with fluid containing produced polymer and traces of oil, which can cause potential incompatibility. Ideally, removal of all produced polymer using a viscosity reducer followed by injection of fresh polymer will improve facility reliability and uptime. Sodium hypochlorite (NaOCl or bleach) was evaluated as a viscosity reducer (VR). Bleach can reduce the viscosity of any HPAM by breaking down the polymer. Polymer destruction fortuitously causes a breakdown of emulsions which releases oil from water and results in improved water quality. After destruction of HPAM, excess bleach was neutralized by chemical means using a neutralizer. After neutralization, the resulting water is free of excess bleach and can be reused for mixing fresh polymer for injection without the risk of degradation of newly mixed polymer. Activating the VR (acidic VR) by pH adjustment can enhance the performance of VR dramatically. Improved oil separation as well as polymer removal can be realized using this technique.
- North America > United States (0.68)
- Asia > Middle East > UAE (0.28)
- Asia > Middle East > Oman (0.28)
- Asia > China > Heilongjiang Province (0.28)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.94)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > France > Chateaurenard Field (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- (2 more...)
Abstract The goal of this work is to develop alkaline-surfactant-polymer (ASP) formulations for a shallow, clayey sandstone reservoir. Commercially available surfactants were used in the phase behavior study. The gas-oil-ratio (GOR) was low; the phase behavior and coreflood study was conducted with the dead oil. The surfactant formulation systems were tested in tertiary ASP core floods in reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for corefloods. The cumulative oil recovery was in the range of 94-96% original oil in place (OOIP) in the corefloods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. The use of alkali and preflush of the soft brine helped minimize surfactant retention.
- Asia > Middle East (1.00)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Missouri (0.28)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (6 more...)
Abstract Steam for enhanced oil recovery is typically generated using Once-Through-Steam-Generators (OTSG) produced at large central facilities with the steam then pipelined to each injection well. As much as 50% of the energy can be lost before it reaches the well bore with the combustion emissions vented to atmosphere. Direct Contact Steam Generation (DCSG) injects both steam and hot combustion flue gases into the reservoir. Oil production is increased by reducing oil viscosity through heat while repressuring the reservoir with flue gases and improving miscibility with the CO2 that remains in the reservoir. This combination greatly improves the Steam-Oil-Ratio (SOR) for increased oil recovery as well as delivering environmental benefits related to reduced water requirements and lower emissions resulting in a much lower carbon intensity. DCSG water requirements are 11% less than OTSG methods as water is created by the combustion process, this water is then injected into the reservoir rather than lost to the atmosphere. As most of the DCSG process emissions are indirect, emissions can be further reduced by as much as 30% with the use of low carbon intensity grid electricity for compression. Pilot results show that DCSG used less water, with 70% of the CO2 retained in the formation. Lower SOR and CO2 retained in the reservoir demonstrates lower carbon intensity relative to OTSG. DCSG offers heavy oil operators a novel, viable, method to economically extract currently uncoverable reservoirs at a lower carbon intensity than traditional methods.
- Asia (0.69)
- North America > Canada > Alberta (0.48)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
Polymer Selection for Sandstone Reservoirs Using Heterogeneous Micromodels, Field Flow Fractionation and Corefloods
Borovina, Ante (OMV Exploration & Production GmbH) | Reina, Rafael E. Hincapie (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Hoffmann, Eugen (HOT Microfluidics GmbH) | Wegner, Jonas (HOT Microfluidics GmbH) | Steindl, Johannes (OMV Exploration & Production GmbH)
Abstract Incremental oil recovery due to polymer flooding results from acceleration of oil production along flow paths and improving sweep efficiency. To achieve favorable economics, polymers should have a high viscosifying power and low adsorption. However, in addition, incremental oil production from various rock qualities needs to be maximized. We developed a workflow using a layered micromodel, corefloods and Field-Flow Fractionation (FFF) to determine the Molecular Weight Distribution (MWD) for the selection of polymers addressing heterogeneous reservoirs. We have designed micromodels consisting of two layers with different permeabilities, one four times larger than the other. The micromodel structure is based on the characteristics of a real sandstone core, with the dimensions 6 cm ร 2 cm. These micromodels were used as preliminary screening of the polymers incorporating heterogeneity effects. Subsequently, single- and two-phase core experiments were performed to determine injectivity effects and displacement efficiency of the selected polymers. In addition, FFF was used to measure the molecular weight distribution, gyration radii and conformance of the polymers. Based on the workflow a polymer was selected. All polymers were tested at target viscosity at 7 1/s shear rate. Micromodel experiments showed that tested polymers are leading to improved sweep efficiency of heterogeneous structure. The displacement efficiency within the higher permeable layer was similar for the investigated polymers whereas the oil recovery from the lower permeable layer showed differences. FFF revealed that the MWD's of the tested polymers were different. The MWD of one of the polymers showed a large number of larger molecules compared with the other polymers. This polymer did not lead to the highest oil recovery in the micromodel. Injectivity and propagation of the higher MW polymer in both single- and two-phase core-floods was falling behind the other polymers. Measurements of the MWD of the core effluent showed that for all tested polymers the larger molecules are initially retained more than the smaller molecules. The polymer with the smallest molecules and narrow MWD showed the best propagation characteristics in the core. Owing to the good performance of this polymer in terms of sweep efficiency improvement, injectivity, and propagation, this polymer was selected for a field application. Therefore, the novelty presented here can be summarised as follow: Heterogeneous micromodels were used to screen polymers for one-dimensional displacement efficiency and sweep efficiency effects Single- and two-phase core floods in combination with Field-Flow Fractionation revealed the impact of the molecular weight distribution (MWD) on polymer injectivity, propagation and retention Selection of polymers need to include MWD to find the most effective polymer Polymer selection needs to take near-wellbore and reservoir effects (micro- and sweep efficiency in heterogeneous reservoirs) into account
- Europe (1.00)
- Asia (1.00)
- North America > United States > California (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (3 more...)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Measurement while drilling (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)
Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods
Hwang, Jongsoo (The University of Texas Austin) | Zheng, Shuang (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Abstract Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model. By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection. Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.
- Europe (1.00)
- North America > United States > Alaska (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.51)
- 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)
- (37 more...)
Abstract Conventional in-situ upgrading techniques use electric heaters to heat oil shale. However, the efficiency of electrical heating method is very slow which requires preheating more than a year. Most conventional heating technologies focused on converting the oil shale, not shale oil reservoirs. The shale oil matrix is very tight and the pore scale is in micro to nano-meter. In this paper, it has been attempted to inject air into hydraulically fractured horizontal wells to create in-situ combustion of shale oil in ultra-low permeability formations. Heat is introduced into the formation through multistage fractured horizontal wells, which enhances the contact area of exposed kerogen. The main focus of this paper is to evaluate the technical feasibility of recovering shale oil resources by air injection. It involves the application of hydraulic fracturing technology to enhance the kerogen exposure to oxygen. Heat flows from the fracture into shale oil formation, gradually converting the solid kerogen into mobile oil and gas, which can be produced via fractures to the production wells.
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Lucaogou Formation (0.99)
- Asia > Russia > West Siberian Basin > Bazhenov Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 9/28a > Crawford Field (0.93)
Associated Polymer ASP Flooding Scheme Optimization Design and Field Test after Polymer Flooding in Daqing Oilfield
Gao, Shuling (Exploration and development research institute of Daqing oilfield company Ltd.) | He, Yixin (No.4 production factory of Daqing oilfield company Ltd.) | Zhu, Youyi (Research Institute of Petroleum Expl. & Dev., CNPC.) | Han, Peihui (Exploration and development research institute of Daqing oilfield company Ltd.) | Peng, Shukai (Daqing oilfield company Ltd.) | Liu, Xiaobo (No.2 production factory of Daqing oilfield company Ltd.)
Abstract There are 54 blocks entered into subsequent water flooding period after polymer flooding in Daqing oilfield, The comprehensive water cut is as high as 97.2% and the average oil recovery factor is 57% for the reservoir after polymer flooding, There are 44% geological reserves still remained underground and these reserves are of good quality for further exploitation. But the reservoir has gone through deepen development by tertiary oil recovery and entered into the period of the fourth enhanced oil recovery, so how to further enhance oil recovery is a world's toughest problem. Therefore a new oil displacing system with high efficiency should be developed suitable for the reservoir after polymer flooding in order to greatly enhance oil recovery for ultra-high water cut reservoir after polymer flooding. In this paper, lots of lab experiments have been carried out consisting of oil displacement performance evaluation and formula optimizing. A new ASP formula using associated polymer has been developed, the incremental oil recovery of this system is 10.35% in the lab experiments of natural cores after polymer flooding. In contrast to linear polymer ASP system, associated polymer ASP system can reduce polymer dosage by 48% and increase oil recovery by 3.3% at the same time. The reservoir engineering and oil displacement scenarios have been worked out and the field test has been carried out in the N3D block with 16 injection wells and 25 production wells after polymer flooding in Daqing oilfield. The numerical simulation predicts the incremental oil recovery can reach up to 8.76% after polymer flooding. The test has entered into field and obtained good technological and economic development effect. The blank water flooding began in Sep 2012 and the trial injection of ASP flooding began in Oct 2013 and the main ASP slug began in Jun 2014. Till Oct 2019, the accumulative injection pore volume was 0.9104 PV with the injection pressure increased by 4.7 MPa, water absorption thickness ratio increased by 27.1%, the biggest water cut decline of single well was 6.4% and the staged incremental oil recovery was 7.89%. At present, the accumulative oil production increment is 0.647 million barrels and the economic benefit is 32.35 million dollars. The numerical simulation prediction shows that the final accumulative oil production increment is 0.657 million barrels and the final economic benefit is 32.87 million dollars. This new technology and field test can enhance oil recovery greatly for ultra-high water cut reservoir after polymer flooding and obtain good technological and economic development effect, so it has a broad application prospect and can be applied extensively in ultra-high water cut blocks after polymer flooding in Daqing oilfield.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)