Wang, M. (Research Institute of Petroleum Exploration and Development) | Xiao, Q. (China University of Petroleum) | Gou, Y. (Research Institute of Petroleum Exploration and Development) | Deng, F. (Research Institute of Petroleum Exploration and Development) | Wang, B. (Research Institute of Petroleum Exploration and Development) | Zhang, D. (Research Institute of Petroleum Exploration and Development)
The Lukeqin Triassic reservoir in Xinjiang, China, is a heavy oil reservoir with high temperature and high salinity. The formation conditions are harsh. With the deepening of oilfield development, the reservoir enters into a high water cut period and faces the problem of stable oil and water control in the middle and late stage of development. In addition, the heavy oil reservoir has complex characteristics, such as deep, thin, thick and so on, so it can not be converted to conventional thermal recovery mode. Therefore, a solution to the reservoir conditions is urgently needed. In order to improve the mobility ratio of water drive, a new type of high temperature resistance and high salinity polymer SWP322 has been developed. In this study, the compatibility, viscosity, temperature resistance, salt resistance and shear resistance of the polymer in Lukeqin reservoir were evaluated and compared with that of HPAM. Finally, the formation conditions of Lukeqin reservoir are simulated to test the percolation and oil displacement ability of the new polymer SWP322 under the conditions of high temperature and high salinity. Experiments show that the polymer has a temperature resistance of 100°C and a salinity resistance level of 2.0×105 mg/L. The experimental results show that the polymer SWP322 has a lower dissolution rate at room temperature than HPAM, but its temperature resistance, salt resistance, shear resistance, and temperature resistance are far better than those of HPAM. With the increase of temperature and salinity, the apparent viscosity of HPAM decreased rapidly, while SWP322 was almost independent of temperature and salinity, and the viscosity retention rate was more than 99%; at the same time, the viscosity retention rate of SWP322 after core shearing also reached 98.6%, which proves that SWP322 is superior to HPAM in its resistance to temperature and salt, and excellent shear resistance also helps to maintain the viscoelasticity of the polymer in the formation. Increase oil displacement efficiency. In terms of seepage capacity, the flow resistance of SWP322 is much better than that of HPAM, and the resistance coefficient and residual resistance coefficient are all more than 5 times that of HPAM; in the process of simulated oil displacement, the displacement efficiency of water flooding is 30.43%, while the flooding efficiency of first polymer flooding and subsequent water flooding is 16.6% higher than that of water flooding; the oil displacement efficiency of double-pipe polymer flooding is 13.19% higher than that of water flooding; the oil displacement efficiency of single tube and double tube flooding system is 16.1% and 23.2% higher than that of water flooding, respectively.
Yang, Liu (Institute of Mechanics) | Lu, Xiaobing (Institute of Mechanics) | Shi, Xian (China University of Petroleum) | Zhang, Kunheng (China University of Petroleum) | Gao, Jian (Research Institute of Petroleum Exploration and Development) | Chen, Xu (Research Institute of Petroleum Exploration and Development) | Zhang, Zubo (Research Institute of Petroleum Exploration and Development)
ABSTRACT: Several laboratory experiments are carried out to investigate the effects of microfractures on stress-dependent permeability. An analytical model depending on pore elasticity theory is proposed to study the related influencing factors. The results show that each curve of stress-dependent permeability is divided into two regions: microfractures closure region and pore compress region. The permeability decreases significantly in microfractures closure region, but it does not change too much in pore compress region. The permeability decreases by about 85~90% in total. It suggests that microfractures deformation cannot recover easily. The analytical solution results present that the volume fraction of microfractures has an important effect on stress-dependent permeability. The stress sensitive coefficient significantly decreases with the ratio of pores volume to microfractures volume (PV/FV). When the value of PV/FV is larger than 2, the stress sensitive coefficient does not change obviously with PV/FV. The high microfractures compressibility is the primary reason why the permeability in tight sandstone presents more sensitivity to effective stress.
The exploration and development of tight oil is a hot topic following shale gas. The fast decline of production is observed during depletion development. It is essential to studying stress-dependent permeability for enhancing oil recovery. However, predicting the stress-dependent permeability is challenging due to the lack of pore change information at microscale. In addition, the tight sandstone is embedded by many microfractures that are easily compressed by effective stress (Chalmers et al., 2012). The changes of matrix pores and microfractures are synchronous under the effective stress, which compounds the difficulties in studying or predicting stress-dependent permeability.
The logarithmic empirical relationship is proposed to describe the relationship between fractured carbonates permeability and effective stress (Jones, 1975). Depending on Poiseuille’s equation, Walsh (1981) also represents the logarithmic relationship based on theoretical derivation procedure. As for fractured porous rocks, a polynomial relationship is derived to express the permeability with effective stress (Gangi, 1978). Dong et al. (2010) proposes that the power law relationship should be used to describe the stress-dependent permeability instead of the exponential relationship. The microfractures that are characterized by high pore compressibility cause strong stress sensitivity in tight oil reservoirs (Cho et al., 2013). In this study, several laboratory experiments are carried out to investigate the effects of microfractures on stress-dependent permeability. In addition, an analytical model is proposed to study the impacts of elastic modulus, Poisson’s ratio and microfractures volume fraction on stress sensitive coefficient.
Chen, M. (China University of Petroleum) | Zhang, S. C. (China University of Petroleum) | Xu, Y. (Research Institute of Petroleum Exploration and Development) | MA, X. F. (China University of Petroleum (Beijing)) | ZOU, Y. S. (China University of Petroleum (Beijing))
ABSTRACT: We developed a new numerical model that is based on a combination of the 2D boundary element method and a complementarity algorithm to simulate the mechanical interaction behavior between a hydraulic fracture (HF) and a horizontal frictional interface (FI). The new model enforces the appropriate contact boundary conditions of the FI using the complementarity algorithm, where the contact modes of the FI are efficiently determined without iterative trial calculation. Heterogeneous FIs were considered and solved by the model, which we validated using the analytical solution of a uniaxial frictional fracture and previously published results related to an HF approaching a natural fracture. Simulation results show that weak horizontal FIs with large slipping zones and shear displacements induced by HFs can confine fracture height. Peak normal stress appears on the two sides of the contact position, and fracture offset occurs in most cases. Fracture offset can be suppressed by an FI with high frictional strength. Heterogeneous FI with variable friction and strength is a key mechanism for fracture offset. Increasing fluid pressure, such as increasing injection rate or fluid viscosity, is conducive to fracture cross.
Hydraulic fracture (HF) height is a crucial issue in hydraulic fracturing [1-2]. Various factors, such as in-situ stress, Young's modulus formation, fracture toughness, and layer frictional interfaces (FIs), influence fracture height growth [3-5]. Among these factors, layer FI is the most difficult factor to be evaluated because its mechanical behavior is complicated  and other factors can be analyzed on the basis of the equilibrium-height model . The mechanical interaction between an HF and an FI should be analyzed for predicting fracture height and fracture geometry.
Numerous studies on the mechanical interaction of HF and FIs have been conducted. The core problem is the accurate description of stress state in FIs, whose boundary conditions are unknown a priori. This problem is simplified by analytical models by assuming the boundary conditions of FIs. Hence, the stress state can be analyzed theoretically. Blanton et al.  proposed an analytical model by assuming the shear zone size and shear stress profile of an FI. Renshaw and Pollard  approximated the stresses along a normal FI to a growing fracture by the first-order stresses near a tensile fracture, which implicitly assumed that the FI was perfectly bonded and did not have any opening or slipping. Gu and Weng  extended Renshaw and Pollard's model to nonorthogonal intersection cases. Chuprakov and Prioul  established an analytical model called “OpenT”, which is based on dislocation theory. The opening and slipping zones of an FI are considered in the OpenT model. Recently, the same authors  improved their model by considering the nonuniform opening profile of an HF orientated orthogonally to the frictional discontinuity. Llannos et al.  determined the slip initiation prior to fracture crossing using the analytical solutions of a constant-pressure fracture. Yao et al.  proposed an analytical model to predict the HF that encounters a natural fracture on the basis of the Griffith stability criterion. Zeng and Wei  analyzed crack deflection conditions using a closed-form solution for the strain energy of an HF.
Liqiu, Ping (CNPC Drilling Research Institute) | Xi, Wang (CNPC Drilling Research Institute) | Xiuling, Zhang (CNPC Drilling Research Institute) | Chenchao, Liu (Research Institute of Petroleum Exploration and Development) | Rui, Yang (China University of Petroleum)
The well construction operation in the pre-salt reservoirs of Santos basin faced great challenges such as the drill string stuck in big-thickness salt formation (more than 2000m) and low penetration rate in the reservoir formation from the beginning of X. Project. The average actual well construction duration of four wells completed in 2015 was 7 days behind the planed period caused by the above-mentioned problems. The well construction cost was more than the approved budget due to the delayed well construction duration. So efforts was concentrated to integrate drilling technology in ultra-deep water to solve drilling challenges in the pre-salt reservoirs to decrease well construction duration and increase exploration and development benefit.
This paper presents an integrated drilling technology to solve drilling challenges in pre-salt reservoirs of ultra-deep water. The combination of near bit reamer stabilizer and synthetic-based mud can prevent the salt formation creeping and decrease the drill string stuck frequency. The optimization of drilling parameters based on mechanical specific energy concept can clearly identify the transfer from the anhydrite formation to the salt formation and drilling penetration rates can be improved in salt formation by optimizing WOB, rotate speed and pump rate, etc. The combination of MPD, turbine drill and impregnated bit can control the mud losses and increase the penetration rates in the carbonate reservoirs which possess poor drillability. All the above-mentioned drilling technology has been applied in two wells and successfully solves the drilling challenges in the pre-salt reservoirs of X. Project.
The combination of near bit reamer stabilizer and synthetic-based mud has decreased the drill string stuck NPT from 11.7d to zero in two wells of X. Project. The average ROP record of the two wells by use of the integrated drilling technology is 24.6 m/h that has been improved 3.4 times comparing the completed four wells in 2015. The drilling duration for 2062m salt section has decreased to from 14 days to 7 days which saved about 14 millions dollars for the two wells. The average ROP in the reservoir formation of the two wells has been increased to 3.45m/h which was about 1.5 times of the four wells' average ROP completed in 2015. The reservoir section has been completed 4.6 days ahead of the planed duration and the comprehensive drilling cost has been saved 5 millions. The integrated drilling technology in pre-salt reservoirs in ultra-deep water made the average well construction duration of the two wells finished in 2016 have decreased to 111 days, however, the average well construction duration of the four wells completed in 2015 was 162 days.
The fastest record of the one well's construction duration was 76 days establishing a new benchmark in pre-salt reservoirs in ultra-deep water. The method to solve well construction challenges in the pre-salt reservoirs of Santos Basin of this paper presented will make a reference for deep water salt formation drilling and offshore oilfields high efficiency development.
Liqiu, Ping (CNPC Drilling Research Institute) | Xi, Wang (CNPC Drilling Research Institute) | Rong, Li (CNPC Drilling Research Institute) | Rui, Yang (China University of Petroleum) | Chenchao, Liu (Research Institute of Petroleum Exploration and Development)
The drilling operation in the more than 2000m thickness pre-salt formation with more than 2000m water depth faced great challenges from the beginning in X. Project of Atlantic due to drill string stuck caused by salt creeping and low ROP, so efforts were concentrated to obtain a better drilling performance as a consequence of the high daily rates of drilling ships.
In this paper, we look for a combination of high performance PDC bits, near bit reamer stabilizer, synthetic based-based mud, MPD, RSS and LWD systems to increase the drilling performance, both in ROP and salt creeping control in salt formations. ROP has been increased by more than three hundred percentages by high performance PDC bits. Near bit reamer stabilizer and synthetic based-based mud made drill string stuck frequency decrease drastically. The combination of MPD, RSS and LWD systems has improved drilling performance. The above-mentioned integrated drilling technology has been successfully applied in two pre-salt wells in one run whose halite formation thickness is 1870m and 2062m respectively in 2016.
The drilling duration for 2062m salt section has decreased to from 14 days to 7 days which saved about 14 millions dollars for the two wells. The average ROP record of the two wells by use of the integrated drilling technology is 24.6 m/h that has been improved 3.4 times comparing the completed four wells in 2015 in X. Project. The NPT caused by drill string stuck has been decreased from the average 11.7 days to zero that can save about 12 millions drilling cost. So the integrated halite drilling technology can not only solve the drilling problems in halite formation in ultra-deep water such as bore hole collapse and drill string stuck but also increase the ROP. The drilling performance in halite formation has been improved and the integrated halite drilling technology has been widely applied in big-thickness pre-salt formation Santos basin and will decrease the drilling duration of ultra-deep water pre-salt reservoirs wells and lower the oil cost per barrel in ultra-deep water development.
The method to increase drilling efficiency in halite formation of this paper presented will make a reference for deep water salt formation drilling and offshore oilfields high efficiency development. Also the method to control salt creeping and drill string stuck might give a light to the drilling operation in gypsum formation in onshore oilfields.
Qiang, Chen (Research Institute of Petroleum Exploration and Development) | Weiye, Han (Research Institute of Petroleum Exploration and Development) | Shouzhi, Huang (Research Institute of Petroleum Exploration and Development) | Tao, Li (Research Institute of Petroleum Exploration and Development) | Qiang, Sun (Research Institute of Petroleum Exploration and Development)
In this paper, SEM and XRED were employed to study the mechanism of scaling and corrosion in the water injection system, nonmetallic composite tubing was developed and evaluated in terms of its ability to resist scaling and corrosion, field operation was carried out to testify this approach.
Zhang, Ming (Research Institute of Petroleum Exploration and Development) | Thomas, Gan (Arrow Energy Pty Ltd) | Yang, Yong (Research Institute of Petroleum Exploration and Development) | Stephan, Tony (Arrow Energy Pty Ltd) | Sibgatulin, Artem (Arrow Energy Pty Ltd) | Mazumder, Saikat (Arrow Energy Pty Ltd) | Chen, Wei (Arrow Energy Pty Ltd)
Coalbed methane (CBM) geology dominance in Surat basin is a coal-based fluvial depositional system. For CBM subsurface modelling, it is still primarily driven by simple deterministic static model and building on the understanding of long extends of coal continuity in lateral distribution. In reality, coal seams (or plies) tend to split or merge laterally across a large distance of few kilometers. Hence, the extend flow contribution or net coal distributions are not homogenous and can changed quite significantly, which we believe using a proper calibrated facies model will be able to predict such behaviors for both coals and its boundary lithology. In our facies modelling work, the coal swamp and shaly swamps depositions are primarily targets for CBM reservoirs and other facies in juxtaposition to them will also influence the lateral continuation of the coal swamp, the heterogeneity of swamp distribution and gas drainage.
This paper summarized four-step procedures to address swamp-based fluvial depositional facies modelling for an integrated approach to identify micro-facies, upscale the coal continuity and sand body, model the lithofacies and estimate the different potential flow patterns based on the multi-realization. This study involved the investigation of a region of 24,000 km2 and the log normalization on the available logs for a quantitative lithofacies interpretation firstly. Then the division of the fining-up sequence cycles, individual ply formation and the boundaries of top of sandstone (together 80,000 tops) have been carefully conducted to derive the variograms and 2D distributions of channels for the description of the coal flow drainage extension. The study focused on the creation of the fluvial facies and five micro-facies of channels, flooding plains, lacustrine, swamp and shaly swamp with geometry parameters, such as the coal thickness, percentage and the channels width, orientation, amplitude, wavelength from the generated 2D maps. The coals continuity and sand body were also thoroughly investigated and upscaled. After structure modeling, the team conducted three-order object facies modeling in reasonable stochastic modelling of fluvial system to descript 3D continuity of the flow patterns of coal swamp. Finally, the coal volume calculation of P10, P50 and P90 has been obtained through the multi-realization of property modeling, which was based on the facies modeling.
The study combines the knowledge of both conventional and unconventional reservoir modelling techniques and the work will be used for better reservoir simulation, as well as basin wide field development planning. In this study, the project team investigated ~1200 wells with geophysical logs, >50 wells with core data, conducted ply formation picking (~40,000 tops) and stochastic static modelling, which successfully correlated and outlined the statistics of sand geometry and ply lengths (areas) to build the concept of fluvial depositional system.
The integrated facies modelling workflow is a novel approach in CBM industry to better understand the coal heterogeneity both lateral continuation and vertical distributions. The geo-statistics outcome will provide multi-realizations for coal and gas production predictions.
Shao, Jie (Institute of Geology and Geophysics, Chinese Academy of Sciences and University of Chinese Academy of Science) | Wang, Yibo (Institute of Geology and Geophysics, Chinese Academy of Sciences) | Lu, Minghui (Research Institute of Petroleum Exploration and Development) | Wu, Shaojiang (Institute of Geology and Geophysics, Chinese Academy of Sciences and University of Chinese Academy of Science) | Xue, Qingfeng (Institute of Geology and Geophysics, Chinese Academy of Sciences and University of Chinese Academy of Science) | Chang, Xu (Institute of Geology and Geophysics, Chinese Academy of Sciences)
This paper presents a random noise suppression method for multicomponent microseismic data by orthogonal matching pursuit of multiple measurement vectors (OMPMMV). Unlike the conventional orthogonal matching pursuit for single measurement vector (OMPSMV), this method assumes all different components data have the same sparsity structure and provides an additional informative coupling between multiple components. So it can process the multicomponent data simultaneously and protect the weak energy on one component by the strong energy constraint on the other components. The examples of synthetic and real data demonstrate the potential of this method for multicomponent data denoising and weak signal protection.
Presentation Date: Wednesday, September 27, 2017
Start Time: 2:15 PM
Location: Exhibit Hall C/D
Presentation Type: POSTER
Chen, Hongling (China University of Petroleum–Beijing) | Cao, Siyuan (China University of Petroleum–Beijing) | Yuan, Sanyi (China University of Petroleum–Beijing) | Zu, Shaohuan (China University of Petroleum–Beijing) | Chen, Shuqiao (China University of Petroleum–Beijing) | Wang, Zhiqiang (China University of Petroleum–Beijing) | Shen, Shian (Research Institute of Petroleum Exploration and Development)
Summary We introduce a robust method to remove interference generated from the simultaneous source acquisition, which improves the method using an iterative seislet thresholding algorithm (ISTA), avoiding the calculation of the local slopes and the assumption that the inverse of dithering operator is equal to its transpose. In this method, we define the value of backward operator as identity operator giving the framework a new physical meaning, and use shaping operator in curvelet domain to provide a coherency-based constrain for the model. The simulated synthetic and field data examples demonstrate the effectiveness of the proposed method and the better performance of inversion results. Besides, this proposed method shows a robust behavior. Introduction The simultaneous-source technique has attracted significant attention of researchers, because of its economic benefits and technical challenges.
Yang, Liu (Institute of Mechanics) | Shi, Xian (China University of Petroleum (East China)) | Zhang, Kunheng (China University of Petroleum (East China)) | Ge, Hongkui (China University of Petroleum (East China)) | Gao, Jian (Research Institute of Petroleum Exploration and Development) | Tan, Xiqun (Research Institute of Petroleum Exploration and Development) | Xu, Peng (Research Institute of Petroleum Exploration and Development) | Li, Lingdong (Research Institute of Petroleum Exploration and Development)
ABSTRACT: The fact that salt ions in shale pores diffuse into fracturing fluids is key factor to lead to recovered water with high salinity. In this paper, the authors conduct the test of mineral composition and SEM to understand the reservoir characteristics. The diffusion experiments are conducted on crushed samples, and a new method is proposed to differentiate between matrix and microfractures by using diffusion data. A large amount of salt ions exit in shale pores and can diffuse into fracturing fluids after fracturing operations. To a great extent, ion diffusion rate is determined by the development of microfractures. The crushed samples with smaller grain diameter contain have lower diffusion rate due to the low probability of microfractures development. When the grain diameter is lower than critical value, the crushed samples cannot contain microfractures. As for Longmaxi formation sample, the fracture-matrix boundary is about 80mesh.The research contributes to understanding the reservoir characteristics and salinity profiles of gas shale.
The field observations show that the salinity of recovered water is generally high. What’s more, the salinity increases continuously over time and even exceeds 10%. It should be noted that the salinity of slick water is about 0.1%. The researchers tend to attribute this observation to the salt ions diffusion into fracturing fluids (Wang et al., 2016).
The salt ions concentration and type in recovered water can act as the indicator to evaluate the development of fracture network. Unlike primary fractures, the secondary fractures are induced fractures that are covered by connate water film. The connate water film can mixes easily with fracturing fluids to increase the salinity of fracturing fluids (Woodroof et al., 2003). The secondary fractures with smaller aperture size tend to forms high exposure area that can enhance the ion diffusion capacity. In addition, the ion type in secondary fractures is different from that in primary fractures (Gdanski et al., 2007). The study found that Ba2+ exits in secondary fractures and the development of microfractures are evaluated based on the concentration of Ba2+ (Agrawal and Sharma, 2013).