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.
Chen, Meiyi (College of Earth Science, Northeast Petroleum University) | Ji, Qingsheng (Exploration and Development Research Institute) | Chen, Shoutian (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation) | Qin, Longpu (Exploration Department Daqing Oilfield Company Ltd) | Cong, Peihong (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation)
Based on the seismic prediction difficulties of the tight sandstone reservoir in Fuyu formation in Zhaoyuan area, single-well sequence division and connecting-well sub-layer correlation are carried out according to logging and lithologic data, and short-cycle interface position is calibrated precisely after a mutual calibration of logging and seismic data. Horizon tracing in the whole area is also carried out to build highfrequency isochronous stratigraphic framework. On this basis, the log facies modes and the sedimentary facies of the short-cycles under a high-frequency isochronous stratigraphic framework are analyzed in the target area, sand-body geometric scale parameters and their relations and sand-body development degree are calculated out, and a sand-body geological model is also built out. According to the seismic data and layer-by-layer geological model of sand bodies, a spatial distribution probability model of facies-controlled sand bodies is built out, which is used to constrain the pre-stack seismic data in facies-controlled inversion calculation. Based on the results of facies-controlled inversion, the tight sandstone prediction is carried out. Finally, a method of isochronal facies-controlled pre-stack seismic inversion prediction of tight sandstone reservoir is formed and it realizes the effective prediction of superimposed sand bodies in target area. Compared with actual drilling results, the sandstone of more than 2m has clear depiction and the sandstone of between 1-2m also has response, which indicates that this method is feasible and practicable.
Si, Xueqiang (Petrochina Hangzhou Research Institute of Geology) | Xu, Yang (Petrochina Hangzhou Research Institute of Geology) | Wang, Xin (Petrochina Hangzhou Research Institute of Geology) | Guo, Huajun (Petrochina Hangzhou Research Institute of Geology) | Li, Yazhe (Petrochina Hangzhou Research Institute of Geology) | Shan, Xiang (Petrochina Hangzhou Research Institute of Geology)
Sandstone can be divided into many types with reference to permeability and porosity. Some scholars and researchers have established criteria to classify tight sandstone by using porosity and permeability. Sandstone with permeability less than 1mD and porosity less than 10% could be called tight sandstone. Exploration and development of tight sandstone gas has become a hot spot of oil and gas exploration (Dai J. et al., 2002) in China. Quite recently, tight sandstone gas reservoirs of different scales have been discovered in the middle-lower Jurassic of Taibei Sag in Turpan-Hami Basin. The purposes of this paperare to analyze the texture and composition of the middle-lower Jurassic tight sandstones, investigate diagenesis type and reveal the influence of diagenesis on reservoir quality.
Luo, Ruilan (RIPED, PetroChina) | Yu, Jichen (RIPED, PetroChina) | Wan, Yujin (RIPED, PetroChina) | Liu, Xiaohua (RIPED, PetroChina) | Zhang, Lin (RIPED, PetroChina) | Mei, Qingyan (PetroChina Southwest Oil& Gas Company) | Zhao, Yi (PetroChina Southwest Oil& Gas Company) | Chen, Yingli (PetroChina Southwest Oil& Gas Company)
Ultra-deep naturally fractured tight sandstone gas reservoirs have the characteristics of tight matrix, natural fractures development, strong heterogeneity and complex gas-water relations. There is strong uncertainty of gas reserves estimation in the early stage for such reservoirs, which brings big challenge to the development design of gas fields. Taking Keshen gas field in Tarim basin as example, during the early development stage, the dynamic reserves were much less than those of proven geologic reserves. As results, the actual production performances are obviously different from those of conceptual design. What are the reasons? How to adjust the development program of gas field? Based on special core analysis, production performance analysis, gas reservoir engineering method, and numerical simulations, influencing factors on evaluation of dynamic reserves for ultra-deep fractured tight sanstone gas reservoirs are analyzed. The results show that rock pore compressibility, recovery percent of gas reserves, gas supply capacity of matrix rock, water invasion are the major factors affecting the evaluation of dynamic reserves. On the basis of above analysis, some suggestions are given for the evaluation of dynamic reserves in Ultra-deep fractured tight sandstone gas reservoirs. For this kind of reservoirs, it is reasonable to determine the gas production scale based on dynamic reserves instead of proven geological reserves.
Cai, Junjie (Shenzhen Branch, CNOOC China limited) | Wen, Huahua (Shenzhen Branch, CNOOC China limited) | Gao, Xiang (Shenzhen Branch, CNOOC China limited) | Cai, Guofu (Shenzhen Branch, CNOOC China limited) | Hu, Kun (Shenzhen Branch, CNOOC China limited)
Huizhou Depression is in the exploration peak stage at present. The main target layer is gradually extending from the middle-shallow traps to the deep paleogene traps and the shallow lithologic traps, and the difficulty of exploration is totally increased. Paleogene layer oil&gas exploration is faced with the problems of deep buried depth, reservoir heterogeneity and uncertain distribution of high-quality hydrocarbon sources.
By combining tectonic evolution analysis with sequence stratigraphy, considering regional stress background and the utilizing of the seismic facies, the main faults tectonic features, stratigraphic sedimentary characteristics, the distribution position of sedimentary center and the control effect of the palaeogeomorphology on the sedimentary distribution range deposited from the transition zone are analyzed.
It is concluded that the lower Wenchang period's tectonic movement was dominated by the southern depression control fault, and the semideep-deep lacustrine high-quality hydrocarbon source rocks were mainly distributed in the south of the Huizhou Depression, such as HZ 26 Sag and the subsag of the XJ30 Sag. The braided river delta deposited from XJ30 transfer zone is mainly distributed along the west side of the long axis of XJ30 sag, and the semideep-deep lacustrine facies mudstone is formed in the east of XJ30 Sag. In the upper Wenchang period, the activity of the depression control faults in the northwest of the Huizhou Depression becomes stronger than the south, which influences the sedimentary center migrated from southeast to the northwest. The sediment provenance of XJ30 transfer zone deposits perpendicular to the long axis of the XJ30, and the long braided river delta is formed in the south side of the XJ24 Sag. In Enping period, which is changed from strong rift phase to rift-depression transition phase, the shallow lacustrine-swamp facies are taken as the main source rocks, and shallow braided river delta is widely developed, while the sediment from the provenance of XJ30 transfer zone is weakened.
The northern and southern migration of the transfer zone provenance river delta and the northern and southern distribution characteristics of the source rocks of semideep-deep lacustrine facies are caused by the differences of the northern and southern fault activities during the Paleogene period. Through the combination of structural evolution analysis and sedimentary characteristics analysis, the analysis of paleogeomorphology's effect on the control of sedimentary system is of great importance to the identification of high-quality paleogene reservoirs and hydrocarbon sources.
Gao, Yongde (CNOOC Zhanjiang) | Chen, Ming (CNOOC Zhanjiang) | Du, Chao (CNOOC Zhanjiang) | Wang, Shiyue (CNOOC Zhanjiang) | Sun, Dianqiang (CNOOC Zhanjiang) | Liu, Peng (Schlumberger) | Chen, Yanyan (Schlumberger)
Drilling in Ledong field at Yinggehai basin of South China Sea faces challenges of high-temperature and high-pressure (HTHP). The high pore pressure and low fracture gradient results in a narrow mud weight window, especially when drilling close to overpressured reservoir. Well LD10-C was the first exploration well targeting at reservoirs in Meishan formation. Well LD10-A and LD10-B were offset wells in a distance of 15-20km drilled for reservoirs in Huangliu formation, which is above Meishan formation. During drilling, both wells encountered severe gas kick, mud loss and did not reach target.
In order to drill and complete well LD10-C safely, a real-time pressure monitoring solution was introduced with integration technique of logging while drilling (LWD) and look-ahead vertical seismic profile (VSP). It helped to monitor pore pressure and fracture gradient while drilling and predicted top of the overpressured reservoir. This enabled to keep the mud weight and equivalent circulation density (ECD) within a safe margin to avoid kick and mud loss, helped to set casing as close as possible to the top of reservoir. The reservoir section was drilled with a manageable mud weight window.
The main achievements of this task were: 1) accurately monitor and predicted pore pressure coefficient at reservoir. The predicted pore pressure coefficient was 2.25 SG versus 2.24 SG from actual measurement. 2) accurate prediction of reservoirs top. The predicted top depth of Sand C was 2m error with accuracy of 0.05%. The top depth of Sand D was 10m error with accuracy of 0.2%. 3) 12.25in section and 8.375in section was successfully drilled deeper with pressure monitoring. The 9 5/8in casing was set 491m deeper and 7in line was set 80m deeper than plan. As a result, well LD10-C was drilled and competed without any drilling complexities.
This was first application of LWD and VSP together for pressure monitoring while drilling in Yinggehai basin. The successful completion of well LD10-C confirmed that this integrated solution was an efficient technique to predict and reduce drilling risks, optimize mud weight and casing diagram, improve operational safety and save cost in HTHP offshore drilling.
Zhang, Yiming (CNPC Huabei Oilfield Company) | Tian, Jianzhang (CNPC Huabei Oilfield Company) | Yang, Dexiang (CNPC Huabei Oilfield Company) | Chen, Shuguang (CNPC Huabei Oilfield Company) | Liu, Xing (CNPC Huabei Oilfield Company) | Hou, Fengxiang (CNPC Huabei Oilfield Company) | Tian, Ran (CNPC Huabei Oilfield Company) | Zhang, Chuanbao (CNPC Huabei Oilfield Company)
The study area is located in the Langgu sag of Northern Jizhong depression, Bohai Bay Basin, East China. In order to achieve exploration breakthrough in deep buried hill, key engineering technologies are developed and used to accurately demonstrate important target identification by recognizing new hydrocarbon accumulation patterns resulting from the analysis of multi-stage structure-controlled trap mechanism and the detailed study of controlling factors over high-quality Ordovician reservoirs based on new high-accuracy 3D seismic data. This study reveals a new evolution mechanism of buried hill controlled by structural superposition, experiencing "the uplift from thrusting in Indo-Chinese to early Yanshan epoch, uplifted block faulting into horsts in middle Yanshan epoch, horsts tilting into belt in Eocene, and belt reversion into trap", and thus puts forward a new mechanism for reservoir forming controlled by a superposition of "dolomite, karsting, and faulting". Three types of reservoir development are identified, including "regional layered pore, local block micropore-fracture, and fracture hole pore layer-block composite", and an accumulation pattern in deep buried hill is constructed, characterized by "efficient hydrocarbon supply from gas-type source rock, predominant migration through fractured surface-nonconformity surface, and stratum- and mass-controlled accumulation", which has guided the 40 years' exploration of Ordovician Yangshuiwu buried hill zone and made a great breakthroughs. Novel relevant exploration technologies have been developed, involving high-accuracy imaging, high-precision well logging identification of hydrocarbon reservoir, ultra-high temperature deep drilling and completion, ultra-high temperature carbonate reservoir stimulation, etc, which solve a worldwide problem that has restricted the exploration of the ultra-high temperature buried hill for many years. These technologies make possible the highest daily production of over 100 m3 oil and 0.5 million m3 gas respectively and sustain a high and stable production for a long term, which guarantee the clean energy supply for Beijing-Tianjin-Hebei region.
Li, zhiye (CNOOC China Limited, Shenzhen Branch) | Liu, Jie (CNOOC China Limited, Shenzhen Branch) | Zhang, Zhongtao (CNOOC China Limited, Shenzhen Branch) | Chen, Zhaominng (CNOOC China Limited, Shenzhen Branch) | Liu, Baojun (CNOOC China Limited, Shenzhen Branch) | Shi, Ning (CNOOC China Limited, Shenzhen Branch)
A series of light oil fields which are characterized by shallow burial, good physical property have been discovered through latest exploration in Baiyun Depression of Pearl River Mouth Basin. However light oil reservoir is "Atypical bright spot" reservoir. The light oil-bearing and gas bearing structures in the seismic section are characterized by "bright spot" reflection, and the difference of elastic parameters is not obvious. Traditional methods are inefficient to discriminate oil, gas and water. Aiming at the above problems, the fluid rock physical interpretation version is rebuilt through the analysis of Gassmann fluid factor based on two-phase medium petrophysics theory and the elastic parameters of the P-wave impedance. Then the three fluid properties of oil, gas and water are classified by direct inversion technique based on elastic impedance. The real data processing and exploration practice have proved the feasibility and validity of this method which is instructive to deep water exploration.