Du, Xuan (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Zheng, Haora (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Wang, Xiaochun (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Hua, Xin (China Petroleum Technology Development Corporation, PetroChina Co. Ltd.) | Guan, Wenlong (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Zhao, Fang (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Xu, Jiacheng (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.)
Heavy oil reservoirs are generally unconsolidated and easy to produce sand during production
Wei, Bing (Southwest Petroleum University) | Zhang, Xiang (Southwest Petroleum University) | Gao, Ke (Southwest Petroleum University) | Li, Yibo (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University)
CO2 injection, either miscible or immiscible, has been recognized as a promising method to enhance oil production for tight reservoirs, with major projects in progress worldwide. This work targeted a tight sandstone reservoir in China, located in the Lucaogou formation of Jimsar sag, Junggar Basin. CO2 injection using huff-puff method was planned to stimulate the oil production because of the rapidly declining productivity of the existing horizontal wells. Although some laboratory works have been conducted for this site, there still lacks the knowledge of mobilizing process of the matrix oil when natural fractures are present. Herein, we present an experimental study of CO2 huff-n-puff in a fractured sandstone rock with the primary objective of elucidating the oil recovery dynamics in different phases under reservoir conditions. The results indicated that the oil recovery rate rapidly decreased with cycle numbers and CO2 huff-n-puff primarily recovered the oil in the large matrix pores. After three cycles, an incremential 32.2% of the original oil-in-place (OOIP) was produced. Based on the dynamics of oil mobilization, the main-determining-forces (MDFs) in this process were re-defined. CO2 displacement, CO2-oil interaction driven by diffusion, and depressurization dominated the first cycle, whereas from the second cycle the first two forces became insignificant. This implied that the soaking phase could be minimized or even eliminated from the second cycle in order to reduce the shut-in time in field application.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Dong, Xuemei (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Zhang, Ting (Surignan Operating Company, PetroChina Changqing Oilfield Company) | Yao, Weijiang (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Hu, Tingting (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Li, Jing (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Jia, Chunming (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company) | Guan, Jian (Research Institute of Geophysical, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield Company)
Pore structure is of great importance in tight reservoirs identification and validation evaluation, especially for formations with developed fractured. However, the conventional pore structure evaluation method based on nuclear magnetic resonance (NMR) logging lost its role. This is because the fractures with width lower than 2mm did not have response in the NMR T2 spectrum. Whereas the porosity spectrum, which extracted from the FMI data, was considered to be effective in fractured reservoir pore structure evaluation. In this study, to quantitatively characterize tight glutenite reservoir pore structure in the Jiamuhe Formation in northwest margin of Junggar Basin, northwest China, 90 core samples were drilled for lab mercury injection capillary pressure (MICP) measurement, and the XRMI data (acquired by the Halliburton and be similar with FMI) was processed to acquire the porosity spectrum.
Xu, Feng (RIPED / CNODC) | Li, Xianbing (RIPED) | Gong, Yiwen (The Ohio State University) | Lei, Cheng (RIPED) | Li, Xiangling (RIPED) | Yu, Wei (The University of Texas at Austin / Texas A&M University) | Miao, Jijun (The University of Texas at Austin / SimTech LLC) | Ding, Yutao (CNODC)
Natural fractures are commonly observed in the unconventional reservoir. Production history indicates that natural fractures have been playing an important role in the oil and gas development progress by improving the permeability of the reservoir and increasing the well productivity. In addition, inappropriate development strategies result in the unreasonable single well oil rate, early water breakthrough, severe damages to the unconventional reservoir and overwhelming economic losses when the fracture properties and distributions are not well understood before the development. Hence, it is of great importance to propose a powerful and efficient workflow to describe the fracture distribution clearly, including building a 3D fracture model, performing history matching and forecasting productions of the unconventional reservoir. In this study, we present a powerful and practical workflow through using Fracflow software and EDFM (Embedded Discrete Fracture Model) to build the 3D DFN (Discrete Fracture Network) model. The main methodology used to perform the fracture modelling allows rigorously handling of both hydraulic fractures and natural fractures that can be identified in an unconventional reservoir. This modelling allows computing the real geometrical fracture attributes (mainly orientation and density) and the spatial distribution of fractures. Fracture conductivity values will be calibrated through a comparison of the Kh(permeability thickness) from the well test to the Kh model computed from the upscaling of the fracture model. The mentioned model above will be built by means of a stochastic simulation constrained by the results of the static and dynamic fracture characterization. In the reservoir simulation phase, EDFM processor combining commercial reservoir simulators is fully integrated to perform history matching and production performance forecast of the unconventional reservoir. With a new set of formulations used in EDFM, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. EDFM provides three kinds of NNC pairs, transmissibility factors, and the connections between fractures and wells. With the aid of the EDFM processor, we can obtain the number of additional grids, the properties of fracture grids, and the NNCs as the simulation input. From the proposed workflow, complex dynamic behaviors of natural fractures can be captured. This will further ensure the accuracy of DFMs and the efficiency offered by structured gridding. The practical workflow for the unconventional reservoir from modelling to simulation highlights the model constrained by the results of the static and dynamic fracture characterization, and the high efficiency to model discrete fractures through the revolutionary EDFM processor. Through this workflow, we can perform history matching effectively and simulate complex fractures including hydraulic fractures and naturally fractures. It potentially can be integrated into existing workflow for unconventional reservoirs for sensitivity analysis and production forecasting.
Dutta, Sandipan (Cairn Oil & Gas, Vedanta Ltd.) | Kuila, Utpalendu (Cairn Oil & Gas, Vedanta Ltd.) | Naidu, Bodapati (Cairn Oil & Gas, Vedanta Ltd.) | Yadav, Raj (Cairn Oil & Gas, Vedanta Ltd.) | Dolson, John (DSP Geosciences and Associates LLC) | Mandal, Arpita (Cairn Oil & Gas, Vedanta Ltd.) | Dasgupta, Soumen (Cairn Oil & Gas, Vedanta Ltd.) | Mishra, Premanand (Cairn Oil & Gas, Vedanta Ltd.) | Mohapatra, Pinakadhar (Cairn Oil & Gas, Vedanta Ltd.)
The Eocene Lower Barmer Hill (LBH) Formation is the major regional source rock in the Barmer Basin rift, located in Rajasthan, India, and has substantial unconventional shale potential. The basin is almost completely covered with 3D seismic, providing an opportunity for more surgical mapping of the rapid structural and stratigraphic changes typical with any syn-rift deposit. Thick sections of organic-rich black shales reaching 400 meters thickness with TOC up to 14 wt. %, were deposited during a period of widespread basin deepening. Algal-rich type I oil prone kerogens dominate in north and generate oil, with very little gas. These shales mature at much lower temperatures than the mixed type I and III kerogens in the south, which also generate much larger amounts of gas and oil, and at higher threshold temperatures. The variable kinetics, as well as rapid facies variations typical of rifts, provide challenges to high-grading and testing unconventional shale plays.
Extensive Rock Eval pyrolysis and source rock kinetic databases were combined with petrophysical analysis to determine log-based porosity and saturations and productive potential. Modified Passey techniques calibrated to NMR log porosities provide estimates of organic richness as well as maturity and shale oil saturation. Basin modeling using Trinity software provides probabilistic ranges of generated and expelled hydrocarbons to determine storage capacity. The modeled oil window storage capacity varies between 6 to 13 MMBOE/km2, comparable to the values observed in Eagle Ford and Barnett Shale plays, but in a rifted basin and not broad cratonic shelf deposits.
Excess pore pressure was modeled using the kinetics of kerogen-to-oil conversion, and is noted in some of the deeper wells in tight sandstones, but not confirmed in the undrilled grabens. These pressure-gradient maps, along with oil properties (viscosity and oil mass fractions) derived from the geochemical model, are used to compute the producibility index. Composited storage capacity and producibility index maps have high-graded potential pilot areas.
In contrast to cratonic shale plays such as the Bakken or Eagle Ford, rapid and substantial facies variations occur due to local input of clastics and variable turbidite geometries which form potential targets for horizontal drilling. Increasingly more detailed paleogeographic maps are highlighting both the challenge and potential of the rich source rock in this basin.
This paper will cover how geochemical, structural, paleogeographic, petrophysical and other data are being used to derisk unconventional potential in this rich and complex rift system. Learnings from future testing of the Barmer Basin shale plays will be important to understand how to develop shale plays in other lacustrine rift basins.
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.
Wenquan, Tang (Sinopec Research Institute of Petroleum Engineering) | Chao, Xiao (Sinopec Research Institute of Petroleum Engineering) | Yuzhi, Xue (Sinopec Research Institute of Petroleum Engineering) | Tian Lu, Zhang Hongbao (Sinopec Research Institute of Petroleum Engineering) | Chengcheng, Niu (Sinopec Research Institute of Petroleum Engineering) | Ruiyao, Wang (Sinopec Research Institute of Petroleum Engineering) | Qingshui, He (Sinopec Research Institute of Petroleum Engineering) | Lingjun, Kong (Sinopec Research Institute of Petroleum Engineering) | Zhifa, Wang (Sinopec Research Institute of Petroleum Engineering) | Haoya, Liu (Sinopec Research Institute of Petroleum Engineering) | Yan, Li (Sinopec Research Institute of Petroleum Engineering)
In order to solve the problem of severe borehole instability while drilling in the S oilfield, technical research on drilling fluids has been carried out. Firstly, the paper analyzes the mechanism and technical difficulties of borehole instability in depth. Aiming at the reasons of borehole instability, the reasonable drilling fluid flowrate was defined by considering hydraulic erosion, drilling fluid plugging property, inhibition, etc, and the anti-sloughing drilling fluid system was optimized by way of strengthening the plugging and inhibiting properties of drilling fluid system. This technology has been applied in more than 40 wells in the S oilfield, the problem of borehole instability in the fractured formation was solved successfully, and the drilling speed was increased by 25.3%, which greatly reduced the downhole complexity and achieved remarkable application effect.
Mao, Rui (Research Institute of Exploration and Development, Xinjiang Oilfield Company PetroChina) | Wang, Zhenlin (Research Institute of Exploration and Development, Xinjiang Oilfield Company PetroChina) | Zhang, Ni (Research Institute of Exploration and Development, Xinjiang Oilfield Company PetroChina)
Tight oil is more and more important in petroleum industry. However, there is few systematic studies up to now. Based on core data, petrophysical experimental data, well logs and test data, a systematic study on seven-property relation of tight oil reservoirs is conducted in Lucaogou Formation, Permian, Jimusaer Sag, Junggar Basin, China. To be specific, firstly, lithology is identified via cross plot of matrix density and constructed structure index from nuclear magnetic resonance (NMR) log. Secondly, using iteration method, lower limit