Jia, Ying (Petroleum Exploration and Production Research Institute, SINOPEC) | Shi, Yunqing (Petroleum Exploration and Production Research Institute, SINOPEC) | Huang, Lei (Research Institute of Petroleum Exploration and Development, Petrochina) | Yan, Jin (Petroleum Exploration and Production Research Institute, SINOPEC) | Sun, Lei (SouthWest Petroleum University)
The YKL condensate gas reservoir is one of the biggest condensate gas reservoirs in China and has been developed more than 10years. At present, the combination of subdivision layer, production speed optimization and horizontal well drilling has been the key to economically unlocking the vast reserves of the YKL condensate gas. The primary recovery factor, however, remains rather low due to high capillary trapping and water invasion. While primary depletion could result in low gas recovery, CO2 flooding provides a promising option for increasing the recovery factor.
The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery (CO2 EGR) of condensate gas reservoir.
Firstly, novel phase behavior experimental procedures and phase equilibrium evaluation methodology for gas-condensate phase system mixed with supercritical CO2 with high temperature were presented. A unique phase behavior phenomena was also reported. Then, CO2 floodingmechanism in condensate gas reservoir was analyzed and clarified based on experiments. Finally, a series of numerical simulation work were conducted as an effective and economical means to maximize natural gas recovery with the lowest CO2 breakthrough by varying strategies, including CO2 injection rate, injection composition, andinjection timing. Meanwhile the CO2 storage volumes of different strategies were calculated.
The results show that higher gas recovery factor can be achieved with CO2 injection through appearing interphase between two fluids, maintaining reservoir pressure, driving gas like "cushion" and controlling water invasion. All strategies have moderate to significant effects on gas production. The control of injection and production ratio needs to be balanced between pressure transient and CO2 breakthrough over the producer to obtain the maximum gas production. The varying injection pressure shows a positive effect of enhancing gas production. Numerical simulation indicated that the recovery of gas reservoir was improved by around 10 percent. The total CO2 storage would be around 30-40% HCPV.
The research showed that CO2 flooding presents a technically promising method for recovering the vast condensate gas while extensively reducing greenhouse gas emissions.
Zhang, Hui (PetroChina) | Wang, Lizhi (Schlumberger) | Wang, Zhimin (PetroChina) | Pan, Yuanwei (Schlumberger) | Wang, Haiying (PetroChina) | Qiu, Kaibin (Schlumberger) | Liu, Xinyu (PetroChina) | Yang, Pin (Schlumberger)
Located at the foothills of Tianshan mountains, western China, the Dibei tight gas reservoir has become one of the key exploration areas in last decade because of its large gas reserve potential. The previous exploration effort yielded mixed results with large variations of the production rates from these exploration wells and many rates are too low to be deemed as discovery wells. Petrophysical properties were excluded as controlling factors because these properties for most exploration wells are very similar. Under the large tectonic stress, heterogeneous natural fracture systems are induced and unevenly distributed in the reservoir, which might be the controlling factor for production. However, due to the limitation of the seismic data quality, quantitative fracture modeling with seismic is not possible for this field. A new method predicting the 3D occurrence of the natural fractures in the reservoir is needed.
In this study, geomechanics-based methods were used to predict the natural fracture systems in the reservoir. The methods started from classification of natural fracture systems based on borehole image and core data into either fold-related and/or fault-related fractures. Geomechanics-based structure restoration was conducted to compute the deformation and the perturbed stress field from the restoration of complex geological structures through time. A correlation was established between the fold-related perturbated stress field and the occurrence of fold-related fractures from wells to predict the 3D occurrence of this type of natural fractures. Meanwhile, the computation of the perturbed stress field around 3D discontinuities (i.e. faults) for one or more tectonic events was conducted by the Boundary Element Method (BEM) until a good match was achieved between the fault-related perturbed stresses and observed fault-related fractures from the wellbore. By using the output from the two methods, the discrete fracture network (DFN) model was constructed to explicitly represent the occurrence and geometry of the natural fracture system in the reservoir in a geological model. A geomechanical model was constructed based on an integrated workflow from 1D to 3D. The fracture stability was then calculated based on the 3D geomechnical model.
Detailed analysis was conducted among the DFN model, the geological model of the reservoir and productivity of the exploration wells, and very good correlation was revealed between the productivity of the exploration wells and the occurrence and geometry of the natural fractures and the structural position of the reservoir.
This study shows that geomechanics-based methods efficiently capture the occurrence of natural fracture systems and reveal the production-controlling factors of the tight gas reservoir. It demonstrates that geomechanics is a powerful tool to support successful exploration of the tight gas reservoir in tectonically stressed environments.
ExxonMobil signed a sales and purchase agreement with Zhejiang Provincial Energy Group for LNG supply. Zhejiang Energy is expected to receive 1 mtpa over 20 years. China Energy Reserve and Chemicals Group is exploring the possibility of importing LNG from the US via ISO containers loaded from the West Coast. Despite the uncertainty spawned by China’s recent decision to levy tariffs on US LNG imports, AGDC said it is still targeting a sale and purchase agreement with Chinese companies by the end of this year. What Does China’s LNG Import Tax Mean for the US? Industry analysts fear bad news for producers, as Chinese demand is expected to be a significant driver in new LNG production.
Understanding and management of water, be it produced, injected, or for use in drilling and fracturing operations, is critical for our industry. This session reviews selection methods and application of chemical additives to solve problems associated with a range of challenges encountered, focusing particularly on scale and microbiology.
This year, as part of the Opening Ceremony, SPE brings you two panel sessions that will focus on the conference theme “Co-operating Towards a More Competitive Environment to Encourage Investment Projects.” The panels will represent two different perspectives—the investors and operators in the region. Digitalisation is emerging as a technological driver of change around the world and is transforming how companies in the oil and gas industry operate. A wave of digital technologies and initiatives are leading this new era of innovation and opportunity. Investments in programmes such as analytics, data science, artificial intelligence, cloud computing, and other emerging technologies are being pursued to improve safety, reliability, and efficiency with the expectation of delivering significant value through improved processes and systems.
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
Sun, Zheng (China University of Petroleum at Beijing, Texas A&M University) | Shi, Juntai (China University of Petroleum at Beijing) | Wu, Keliu (China University of Petroleum at Beijing) | Gong, Dahong (CNPC Bohai Drilling Engineering Company Limited Directional Well Technology Services Branch) | Peng, Hui (CNPC Bohai Drilling Engineering Company Limited Mud Logging 2) | Hou, Yuhua (NO.2 Logging Branch of Bohai Drilling Engineering Co., Ltd., PetroChina Group) | Ma, Hongyan (CNPC Bohai Drilling Engineering Company Limited Directional Well Technology Services Branch) | Wang, Daning (CNPC Bohai Drilling Engineering Company Limited Directional Well Technology Services Branch) | Ramachandran, Hariharan (The University of Texas at Austin) | Liu, Yisheng (China University of Petroleum at Beijing) | Liu, Wenyuan (China University of Petroleum at Beijing) | Wang, Suran (China University of Petroleum at Beijing) | Li, Xiangfang (China University of Petroleum at Beijing)
With respect to the sharp increase in population all around the world, more and more energy and fuels are expected to achieve the counterbalance between supply and demand. Deeply attracted by its considerable and prospect recovery reserve, the exploitation, development and related research contents regarding coalbed methane (CBM), i.e., one of the unconventional gas reservoirs, are currently heat and essential topics. Without any doubt, precise determination of coal permeability will dramatically contribute to the development efficiency of CBM reservoirs. It should be noted that the permeability in CBM reservoirs possesses unique heterogeneous characteristics, especially for the different permeability at directions of face cleats and butt cleats, which will inevitably result in greatly shape-change for fluid flow field and eventually the production performance. To my best knowledge, nearly all the previous methods proposed for evaluating coal permeability assume the homogeneous permeability feature in CBM reservoirs, which show fairly great discrepancy compared with that of the realistic situation. In this work, in order to address this urgent issue, a novel permeability evaluation method is developed for the first time, which is able to generate precisely heterogeneous characteristics of coal permeability based on the water production rate versus production time curve at the early production stage. First of all, considering both orthotropic heterogeneous permeability and pressure propagation behavior in CBM reservoirs, single water phase productivity equation is seriously derived. Secondly, for simply usage purpose in field application, the obtained equation is transformed through linearization treat. Finally, combining the water production performance with the linearized equation, efficient iteration calculation procedures are given to determine the heterogeneous permeability feature. Also, the skin factor of corresponding CBM well can be determined. The applicability and accuracy of the proposed method have been successfully verified through field application. In sum, the proposed method can serve as a simple as well as an accurate tool to determine the crucial heterogeneous permeability feature in CBM reservoirs. More importantly, during the determination process, the method just requires the water production performance at the early production stage, which means that the obtained permeability characteristics can be utilized to guide production strategy adjustment in the following gas production stage. As a result, the proposed method can be regarded as a necessary preparatory work before gas production takes place in CBM reservoirs, which will play a positive and active role in optimization of ultimate gas recovery and well configuration.
Wu, Xiaye (The University of Oklahoma) | Han, Lihong (Tubular Goods Research Institute of CNPC) | Yang, Shangyu (Tubular Goods Research Institute of CNPC) | Yin, Fei (Chengdu University of Technology) | Teodoriu, Catalin (The University of Oklahoma) | Wu, Xingru (The University of Oklahoma)
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.
To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.
The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.
The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
Sun, Zheng (MOE Key Laboratory of Petroleum Engineering and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Shi, Juntai (MOE Key Laboratory of Petroleum Engineering and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Wu, Keliu (MOE Key Laboratory of Petroleum Engineering and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Zhang, Tao (MOE Key Laboratory of Petroleum Engineering and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Feng, Dong (MOE Key Laboratory of Petroleum Engineering and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing)) | Li, Xiangfang (MOE Key Laboratory of Petroleum Engineering and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing))
Low-permeability coalbed-methane (CBM) reservoirs possess unique pressure-propagation behavior, which can be classified further as the expansion characteristics of the drainage area and the desorption area [i.e., a formation in which the pressure is lower than the initial formation pressure and critical-desorption pressure (CDP), respectively]. Inevitably, several fluid-flow mechanisms will coexist in realistic coal seams at a certain production time, which is closely related to dynamic pressure and saturation distribution. To the best of our knowledge, a production-prediction model for CBM wells considering pressure-propagation behavior is still lacking. The objective of this work is to perform extensive investigations into the effect of pressure-propagation behavior on the gas-production performance of CBM wells. First, the pressure-squared approach is used to describe the pressure profile in the desorption area, which has been clarified as an effective-approximation method. Also, the pressure/saturation relationship that was developed in our previous research is used; therefore, saturation distribution can be obtained. Second, an efficient iteration algorithm is established to predict gas-production performance by combining a new gas-phase-productivity equation and a material-balance equation. Finally, using the proposed prediction model, we shed light on the optimization method for production strategy regarding the entire production life of CBM wells. Results show that the decrease rate of bottomhole pressure (BHP) should be slow at the water single-phase-flow stage, fast at the early gas/water two-phase-flow stage, and slow at the late gas/water two-phase-flow stage, which is referred to as the slow/fast/slow (SFS) control method. Remarkably, in the SFS control method, the decrease rate of the BHP at each period can be quantified on the basis of the proposed prediction model. To examine the applicability of the proposed SFS method, it is applied to an actual CBM well in Hancheng Field, China, and it enhances the cumulative gas production by a factor of approximately 1.65.