Tongyi, Zhang (Research Inst. Petr. Expl/Dev) | Wei, Pang (Sinopec Research Institute of Petroleum Engineering) | Juan, Du (Sinopec Research Institute of Petroleum Engineering) | Jun, Mao (Sinopec Research Institute of Petroleum Engineering) | Ying, He (Sinopec Research Institute of Petroleum Engineering) | Qiong, Wu (Sinopec Research Institute of Petroleum Engineering) | Xiaoxu, Feng (Sinopec Research Institute of Petroleum Engineering) | Panglu, Jiang (Sinopec Research Institute of Petroleum Engineering) | Dejia, Di (Sinopec Research Institute of Petroleum Engineering)
Designing hydraulic fracture stimulation to optimize well productivity requires knowledge of the initial reservoir pressure and permeability, the closure stress magnitudes in the reservoir and in bounding formations, a carrier fluid with a suitable leakoff coefficient, and rock properties such as the Young’s modulus and the Poisson ratio. When key parameters are left unknown, the hydraulic fracture stimulation is likely to be severely suboptimal.
This study integrates pressure buildup and production transient
analyses with microseismic surveys and the recorded pumping schedule to estimate the above-mentioned parameters in previously fractured wells on production for up to 7 years from a tight gas reservoir.
The first well completed in the block included a pressure buildup test that enabled accurate estimation of the initial reservoir pressure and permeability. A post-fracture buildup test was also conducted, and annual pressure buildup tests in 6 subsequent years showed continuous changes in the fracture morphology with fracture conductivity decreasing by a factor of 3 and fracture length increasing by about 50%. Many of the subsequent wells were drilled in 2 pattern well clusters, each designed to account for fracture propagation behavior indicated from a microseismic survey. A comparison with an optimal hydraulic fracture design intended to maximize well productivity indicates that most of the well stimulations were suboptimal with rate and cumulative production about ½ that of an optimized design.
The observed changes in fracture conductivity and length over time were unanticipated. Because such data are rarely recorded the variations in fracture morphology that should be of considerable interest to pressure transient analysts. The fracture treatment analysis shows a comparison between the actual fracture treatment and one designed to maximize well productivity and clearly illustrates the potential for well improvement using modern hydraulic fracture design principles.
In recent years, the screw pump is used as a new artificial method for it has the advantages of less investment, simple device structure, conventional operation, obvious energy saving and strong adaptability. It could reduce the cost of production effectively and improve production efficiency. Now it has become the main method of oil field mining machine. With the maturity of the ground drive screw pump oil recovery technology, many new forms of injection-production technology gradually applied to the screw pump well, such as, the downhole double screw pump oil-water separation system. For the torque which load on the whole system increases considerably than conventional screw pump, Higher mechanical property requirement of the supporting hollow sucker rod is needed, the failure area mainly concentrated on the screw thread joint. The Stress analysis was applied to the 34 hollow sucker rod which is supported on the on and off attachment of the downhole double screw pump oil-water separation system. According to the stress analysis results, shape optimization was applied on the root shape of the screw thread, the stress distribution of the screw thead on hollow sucker rod joint was improved, the mechanical property of the screw thread joint of hollow sucker rod was improved.
Keywords: Screw Pump, Hollow Sucker Rod, Screw Thread Joint, Shape Optimization
Li, Qiaoyun (Research Institute of Petroleum Exploration and Development) | Wu, Shuhong (Research Inst. Petr. Expl/Dev) | Wang, Baohua (Research Institute of Petroleum Exploration and Development) | Li, Xiaobo (Research Institute of Petroleum Exploration and Development) | Li, Hua (Research Institute of Petroleum Exploration and Development) | Zhang, Jiqun (Research Institute of Petroleum Exploration and Development) | Meng, Lixin (Research Institute of Dagang Oilfield, PetroChina)
Reservoir numerical simulation, which interests a large amount of reservoir engineers, is an important tool in oilfield development researches. This paper introduces a new generation simulator, which can be used to simulate the traditional and pseudo-compositional reservoirs. This simulator adopts finite volume method, completely implicit time discretization technology (CITDT) and dynamic space discretization technology (DSDT). The multilevel preconditioner solver, which is applied in the simulator, can enhance the computation speed. In this paper, a mature heterogeneous water-flooding oilfield with 30a's development history is simulated by this simulator. In the course of development, there are 242 producers and injectors drilled, and the exploitation strata-series are adjusted frequently. Currently the reservoir has entered the "double high?? stage, more than 79% of recoverable reserves have been produced and the water-cut reaches to 90%. After history-matching and production prediction by this simulator, the results shows that this reservoir numerical simulator can be used to simulate the complex reservoirs with long development history and mounts of wells, and it can describe the production performance precisely. Moreover, the case study indicated that the new generation simulator is a fast and adaptable tool to simulate the complex reservoirs with large scale, which shows its high potentiality in industrial application.
Water-flooding is a widely used recovery method of mature oilfields. In recent years, most of the mature oilfields are already at the medium-high even ultra-high water cut period due to water breakthrough and invalid water circulation. Air foam injection has been optioned as an EOR technique to block high permeability water zones and/or increase sweeping and displacement efficiency. There are medium-high average permeability (1016×10-3µm2) oil bearing formations and ultra high permeability layers or channels after water flooding in Dagang oilfield, Petrochina. After 42 years of water injection, the recovery efficiency achieved was only 37.6%, but average water cut has reached to over 97%. In this study, Laboratory experiments were focused on low-temperature-oxidation (LTO) characteristics of oil samples, selection and evaluation of the foam agent and core foam-flooding. Through isothermal oxidation experiments, the influence of formation sand, formation water, foams, clay mineral, temperature and pressure on LTO reactions is investigated qualitatively. It is also analyzed that the changes of component and properties of crude oil before and after the LTO reaction. Selection and evaluation of basic property of the foam agent on formation condition has been done through the device of high temperature and high pressure foam agent evaluation. After that, some dynamic foam displacement experiments are also performed, including single-tube and parallel tubes displacement experiments of air foam at different water saturations. Experiments prove that during the air foam flooding process, oxygen can be effectively consumed in the formation, and the foam can effectively plug high permeability layers to expand swept volume. A pilot project has been designed according to the study in Dagang oilfield. The issues related to safety and corrosion control during air injection and the project economic assessment were also addressed in this paper.
There are many reasons for the low fluid volume of oil wells and decreasing injectability of the polymer injection wells, such as the unreasonable process, the variations of the formation conditions, imperfect injection-production pattern, and improper production management, etc., and moreover, another important factor is the injected polymer and cross-linked polymer jamming in the near wellbore area and deep oil reservoir. According to the Statistical analysis of the 289 wells in Daqing Oilfield, there are two situations existing in polymer jamming which caused decreasing injectability, one is the shallow blocking, blockage radius within 3 meters, mainly caused by the polymer micelles, polymer floc, mechanical impurities, salt scale and iron sulfide, etc.; the second is the deep formation block, blockage radius around 10 meters, there are two factors resulting in this situation, which are, high viscosity caused near wellbore area jamming and polymer retention and adsorption in far wellbore zone. Aiming at these two situations, we have developed the polymer blockage remover and its supporting technology, which can efficiently remove blockage from polymer / cross-linked polymer, through this technology, the injection stop or under-injection can be solved to some extent, and the development effects of the polymer injection area have been improved.
Wu, Yongbin (RIPED, PetroChina) | Li, Xiuluan Xiuluan (RIPED, Petrochina) | Jiang, Youwei (RIPED, Petrochina) | Wang, Hongzhuang (Research Inst. Petr. Expl/Dev) | He, Wanjun (Research Institute of petroleum Exploration & Development, Xinjiang Oilfield Company.)
In Xinjiang, China, a huge volume of heavy oil deposits is not commercially developed yet due to the high in-situ oil viscosity that is higher than 100,000 to 1,000,000+ cp and the strong reservoir heterogeneity. Two SAGD pilot tests with 11
wellpairs in total have been carried out since 2008 while the extensively distribution of shale barriers result in the poor SAGD steam chamber conformance, low production rate and high SOR.
This paper presents the workflow to break shale barriers to improve the steam chamber development along horizontal section, to reduce the SOR and to enhance the economic performance. The first step of the workflow is to select representative core and shale barrier samples and quantify the geomechanic data by high-pressure-high temperature dilation and shale barrier failure experiments. Meanwhile, the geologic model is built taking into account geological uncertainties of the reservoir and the core analysis results. And then, a small set of SAGD wellpair models are selected as the typical wellpair models by classifying different patterns of shale barriers distribution along horizontal section. Finally, the upscaled thermal reservoir
models with geomechanics models using the data acquired by geomechanic experiments are investigated to model and optimize operation strategies for dynamic fracturing and shale barrier failure during SAGD phase.
The research reveals that the high-pressure CSS is an effective method to break the shale barrier distributed between the horizontal segments of the producer and the injector, which has been verified by field experience and the numerical simulation. It is forecasted that the case without HP-CSS will have the steam chamber growth at 50% percent of horizontal segment, which is 40% less than the case CSS. The ultimate oil recovery factor is 34.54%, which is 16.31% less than the case with HP-CSS; and the cumulative oil/steam ratio is 0.175, ,which is 14.5% less than the case with HP-CSS, encouraging SAGD performance after HP-CSS shows a better economic performance, which is worthwhile to carry out and also has a significant guidance for the similar SAGD reservoirs to improve the performance.
Wu, Yongbin (PetroChina Co. Ltd.) | Li, Xiuluan (Research Inst. Petr. Expl/Dev) | Liu, Shangqi (Research Inst. Petr. Expl/Dev) | Ma, Desheng (Expl & Dev Rsch Inst Liaohe Co.) | Jiang, Youwei (Research Inst. Petr. Expl/Dev)
Thermal recovery technology particularly cyclic steam stimulation (CSS) is always an effective means to develop the conventional heavy oil reservoirs, which can be validated from literature. While most of the heavy oil reservoirs developed by CSS are the thick, well-deposited, high quality reservoirs and there are no much reports of producing oil from mid-depth oil reservoirs with large acquifers.
In this paper, according to the petrophysical properties and geologic characteristics of the target block F in Greater Fuld oilfield in Sudan, based on the oil test results, detailed 3D geologic model is established and the type well model for CSS and SF is extracted, to study the real performance with the real geological properties.
The development zone, the perforation strategies, the cylic steam injection quantity, the steam injection rate, soak time, and cyclic period are optimized for CSS. Based on the production performance of CSS, the optimal cycles of CSS followed by SF is determined. And the wellpattern and well spacing, the parameters of SF such as unit steam injection rate, steam quality, effects of bottom acquifer on the SF are also simulated and optimized. The simulation results indicate that the thermal recovery technique especially 4 cycles of CSS followed by SF can acquire satisfied performance, which shows an effective and economic future in the development of the heavy oil deposits in Greater Fula Oilfield.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration & Development, CNPC) | Weng, Rui (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration & Development, CNPC) | Luo, Yousong (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration & Development, CNPC)
For mature oil fields, foam flooding is an attractive chemical EOR technique and many pilot tests have been carried out in China. The performance of foam flooding pilot tests and its affect factors on oil recovery was discussed in this paper. The development trend and key technologies of foam flooding technique are pointed out.
Eighteen foam flooding pilot tests have been carried out in China from 1994 to 2010. Good performance have achieved in sixteen pilot tests. Through effects analysis of the pilot tests, three main aspects are concluded for affecting the performance of foam flooding tests. First, the characteristics of target reservoirs influence effects of foam flooding tests. The performance of foam flooding in higher oil viscous reservoirs is better than that in light oil reservoirs. The reservoir temperature and formation water salinity also influences the effects of foam flooding. Secondly, the chemical formula of foam solution and the size of slug influence the performance of foam flooding. The stability of foam formula influences the effects of foam flooding greatly. With the same amount of surfactant solution, the effect of high concentration small-sized slug is better than that in low concentration large-sized slug. Last, the injection method and gas liquid ratio can directly influence the foam performance in the reservoir, gas and liquid mixing injecting model is better than surfactant solution-alternation-gas (SAG) injection, and reasonable gas liquid ratio is important for guarantee good effects of foam flood.
At present, the trend of foam flooding in China is from nitrogen foam flooding and natural gas foam flooding to air foam flooding. The key technologies of foam flooding are the development of high stable foam formula with oil tolerance, salt and temperature resistance, good injection method and reasonable injection parameter etc.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Wang, Zhe (Research Institute of Petroleum Exploration and Development, CNPC) | Wu, Kangyun (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Long, Hang (Research Institute of Petroleum Exploration and Development, CNPC)
Lab study of chemical EOR for the carbonate reservoir was performed through core characterization, chemical formula screening, surfactant adsorption losses experiments and oil displacement core flooding tests of chemical flooding.
The research results lay the foundation of future pilot tests for chemical combination flooding applying to carbonate reservoirs.
Core characterization by scanning electron microscope and mercury injection capillary pressure experiment prove that there are plenty micropores and a few emposieu within rock, porosity of formation cores is relatively high but permeability is low, the reservoir lithology belonged to typical biostromal carbonate reservoir and the heterogeneity is severe. Chemical flooding formula was investigated by polymer and surfactant screening tests. Salt tolerant polymers including STARPAM and KYPAM showed good viscosifying performances than conventional polymer when prepared with formation water. Amphoteric surfactant AS-13 and anion-nonionic surfactant SPS1708 were selected and ultra-low interfacial tension between crude oil and formation water can be obtained in alkali-surfactant-polymer (ASP) and alkali free surfactant-polymer (SP) systems. Adsorption losses of surfactants on core sample showed that the dynamic adsorption losses of surfactant AS-13 and SPS1708 were 0.46mg/g and 0.37mg/g respectively. Core flooding tests of chemical flooding proved that more than 17~18% incremental oil recovery over water flooding could be obtained with ASP (0.6wt% Na3PO4 + 0.3wt% surfactant + 1000ppm polymer) or SP (0.3wt% surfactant + 1000ppm polymer) flooding. The effect of both ASP and SP flooding was better than that of surfactant flooding.
The experimental results are considered to be technical feasibility and confirm the effectiveness of chemical EOR methods especially the SP flooding for the biostromal carbonate reservoir, which may present further understanding for chemical EOR field application in carbonate reservoirs.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Weidong (Research Institute of Petroleum Exploration and Development, CNPC) | Cheng, Lijing (Oil Production Engineering Research Institute of Dagang Oilfield) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration and Development, CNPC)
Surfactant-Polymer (SP) flooding has attracted lots of attention among chemical combination flooding researchers in recent years. Pilot tests of SP flooding in China were introduced and key factors influencing the performance of pilot tests were analyzed in this paper. Main technological problems occurred in pilot tests were indicated. Suggestions concerning technology improvement and development were given.
About ten SP flooding pilot tests were carried out in China since 2003. These target reservoirs were characterized with high permeability and low permeability sandstone, conglomerate, and high temperature and high salinity ones respectively. At present, the performance of SP flooding pilot tests in Gudong Block 6 and Gudong Block 7 of Shengli oilfield have shown good enhanced oil recovery (EOR) effect. It confirmed SP flooding could improve both of oil displacing efficiency and sweep efficiency and EOR ability for SP flooding is better than that of polymer flooding. EOR effect of SP flooding can be reflected from the following two aspects. Firstly, with SP slug injecting, the pressure of injection well increased and fluid entry profile was adjusted. The performance of profile control was favorable. Secondly, ultralow interfacial tension could be achieved and residual oil was displaced significantly. SP flooding showed stronger ability in decreasing water cut and increasing oil production than polymer flooding. The production history data showed that main factors influencing EOR were the corresponding relationship between injection wells and production wells, the chemical formula properties and the injection amount of SP system. The favorable oil production was obtained when the corresponding relationship between injection wells and production wells was good. The quality stability of SP formula could influence the flooding EOR performance greatly. Small injection slug size of chemical system would lead low EOR level.
The key technologies which should be improved and optimized for SP flooding are displacing agent quality, formula system stability, slug design, well pattern and so on.