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
Li, Qinghui (Qianhai Harbour Energy Technology Development Shenzhen Co., LTD) | Zhu, Jinzhi (Petrochina Tarim Oilfield Company) | Li, Shaoxuan (Xidian University) | Zhang, Shaojun (Petrochina Tarim Oilfield Company) | Hisham, Nasr-El-Din (Texas A&M University) | Ren, Lingling (Petrochina Tarim Oilfield Company) | Li, Jiaxue (Petrochina Tarim Oilfield Company) | Al-Mujalhem, Manayer (Texas A&M University)
Global energy demand has driven the petroleum industry to develop hydrocarbon resources from extremely harsh formations which contain ultra-high pressure and temperature (HPHT) reservoirs. Ultra-high density drilling fluids are critical to successful drilling and completion practices in all of these wells. In this paper, potential weighting materials were systematically evaluated and screened to accomplish an ultra-high density oil-based drilling fluid system (19.62 to 22.12lb/gal) aimed to utilize in ultra HPHT conditions (>30000psi and >410°F).
Several potential high-density weighting materials were evaluated in the laboratory conditions. Basic properties (pure density, particle size/distribution, surface area etc.) were evaluated and compared. Special treatments were conducted to optimize the properties of weighting materials. HPHT filtration tests under static and dynamic conditions were conducted at higher than 410°F and 300 psi. Real cores with an average porosity of 19% and an average permeability of 50 mD were used in the filtration tests. Rheological properties, sag tendency, the volume of filtrate, and the filtrate cake characterization of oil-based drilling fluids were measured before and after heating at 410°F for 16 hours.
Results revealed that ultra-micro manganese and ilmenite complex after suitable surface treatment could act as an ideal weighting material than ultra-pure barite or other materials, which could fail in rheology and sag controlling measurement with such high temperature and density. The viscosity and filtration analysis confirmed the stability and reliability of this novel ultra-high density oil-based drilling fluid.
This study developed a challenged drilling fluid system under critical testing states, as well as established a systematical laboratory evaluation and screening procedure of weighting materials for ultra-deep wells and contributed recommendations on how to utilize it in the fields.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Kong, Debin (China University of Petroleum, Beijing) | Ma, Ruicheng (China University of Petroleum, Beijing) | Li, Binhui (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing)
Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention.
Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits.
Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10–3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue.
Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.
Cai, Bo (Research Institute of Petroleum Exploration & Development, PetroChina) | Duan, Guifu (Research Institute of Petroleum Exploration & Development, PetroChina) | He, Chunming (Research Institute of Petroleum Exploration & Development, PetroChina) | Gao, Yuebin (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Yang (Research Institute of Petroleum Exploration & Development, PetroChina) | Xu, Zhihe (Research Institute of Petroleum Exploration & Development, PetroChina) | Jiang, Wei (Research Institute of Petroleum Exploration & Development, PetroChina)
X oil field was located in eastern China. The lithological component of formation is fine sandstone. The typical characteristics are low-permeability and low-porosity with high viscosity, resin and asphaltene contents, the detail characteristics as follows:1)Shallow buried depth (650~850m); 2)Low permeability and low porosity(the average permeability is 1.0×10−3μm2 and the average porosity is 10%); 3)High oil viscosity,asphalt and wax content (15.2 API,24.3%and17.8%,respectively);4)Ultra-low temperature(45~53°C) with high solidify point(nearly 30°C);5) High content of clay (from 14 to 23%)and high content of velocity-sensitive minerals such as illite, almost 80 percent of wells need hydraulic fracturing treatment, therefore, hydraulic fracturing stimulation is an important technology for this tight heavy oil formations. Over the past two decades, conventional fracturing treatment has far away from satisfaction as a result of high viscosities, poor flow properties and high solidify point in compared to conventional oil. Therefore, a systematic technologies are put forward in this paper, the highlights are:1) Systematic fine formation evaluation prior to fracturing design which contains mineral gradients, nuclear magnetic resonance, rock mechanics, in-situ stress profile, X-CT scanning and so on; 2) A new finely processed pre-pad fluid is developed, and the asphalt and wax content can be reduced through completely miscible between oil and fluid interaction; 3) Low polymer concentration fracturing fluid and variable viscosities are utilized in different treatment stages. The concentration is only 0.2%-0.28% and residue content is 82mg/l reduced 45% and 35% that of the past fracturing fluid,4)Many fracturing treatment parameters are changed such as proppant's type and size, fracturing fluid's type, tip screen-out (TSO)fracturing in order to improve fracture conductivity, liquid nitrogen injection to pad fluid with multi-stage slurry injection schedule, and pumping rate as well, which makes it not only to ensure the successful treatment but also to maximize fracturing treatment potential; 5) Counter measures are applied systematically such as systematic quality control, optimization shut-in time for improve propped profile and flow back, post-treatment management, etc.
More than 120 treatments with new technologies in X tight heavy oil field have been performed with encouraging results,95% efficiency with accumulated incremental oil of 110,500 tons and the average post-fracturing rate reach to 10.5m3/d increased more than 50% that of the past well stimulation under the same formation conditions.
The novel hydraulic fracturing technology provides a new way to maximize recovery efficiency with in low-permeability heavy oil reservoirs. It also has important strategic significance for development and exploration promotion of these unconventional reservoirs.
Dong, Mingda (China University of Petroleum - Beijing) | Yue, Xiang’an (China University of Petroleum - Beijing) | Qu, Shiyuan (China University of Petroleum - Beijing) | Sun, Fengrui (China University of Petroleum - Beijing)
Cyclic steam stimulation is one of the important ways to develop heavy oil. In the past research, saturated steam and superheated steam were mainly used as injected fluids. With the advancement of technology, supercritical water cyclic steam stimulation began to receive more and more attention.
Thermodynamic oil recovery is the main way of heavy oil development, and supercritical water as a displacement medium for thermodynamic oil recovery has high pressure, high thermal enthalpy value and low density which makes it easy to spread in formation. At the same time, supercritical water also has some special properties, its polarity will reverse under high temperature and high pressure, which is beneficial to the mutual solubility of supercritical water and crude oil, increasing the efficiency of oil displacement.
In this paper, a cyclic steam stimulation model is presented for estimating recovery factors and production rates of different injection fluids, and the corresponding parameters are derived by a pilot field test. Firstly, a steam stimulation model using different injection fluids is proposed based on the properties of supercritical water, saturated and superheated steam. Secondly, according to the established model, the effect of the state of injected water on production rate and recovery factor of cyclic steam stimulation was studied. Thirdly, using supercritical water as the displacement medium, the effect of injection rate on production rate and recovery rate of cyclic steam stimulation was studied. Finally, the optimal production rate is obtained by analyzing the results.
Results show that: (a) Supercritical water can better heat the formation during steam stimulation than saturated and superheated steam. (b) Supercritical water has better injection capacity than saturated and superheated steam. (c) Cumulative oil production when injecting supercritical water is greater than the injection of saturated steam and superheated steam. (d) Cumulative oil production of supercritical water injection increases as injection rate rises. (e) The higher the injection rate is, the higher the production rate at the same production time.
With the purpose of studying Chinese mainland shallow crustal stress state, we have built a spherical shell finite element model including main active faults, tectonic blocks, topography, and Moho discontinuity with the consideration of lithospheric heterogeneity. In this model, we deem gravity and plate tectonic stress as the main influential factors, and use the in-situ stress as the main constraints to make the simulation results and in-situ stress measurement comparable. By this way, we obtain the absolute value estimations of China mainland stress field.
Numerical results are: (1) the general directions of maximum horizontal stress are distributed radially with the center of Tibetan Plateau. From east to west, the directions of maximum horizontal stress gradually rotate clockwise from NS to NNE, NE, NEE, SE, consistent with previous results of focal mechanism solution; (2) the stress states in different study regions vary greatly. Stress is obviously lower in the center of Qinghai-Tibet active block and higher in its surrounding areas; (3) the maximum and minimum tectonic stress σΗ and σh are mainly compressive at the depth of 2000 meters in the shallow crust of Chinese mainland, and the magnitude range are 14.5MPa < σΗ <58.0MPa and 3.8MPa < σh <26.7MPa respectively.
The in-situ stress measurement method is a primary means to understand the present-day state of stress, but due to the measurement restriction, we can only measure the shallow crust stress state. How to take advantage of various known data to analyze the regional crustal stress state quantitatively is a complex problem involving geology, mechanics, mathematics and many other disciplines. The formation of tectonic stress field is determined by many factors such as tectonic movements, geological lithology, topography, rock weight, etc. In-situ stress is the result of the combined effects of these factors. Based on the measured data of stress, the deduction of stress in non-measured region can be regarded as a process of simulating the effects of these factors. In this paper, finite element method is applied to calculate the absolute stress of the shallow crust in China. The fundamental concept of our research is following: (1) Establish our finite element model with the consideration of previous studies concerning geology, geophysics, rock mechanics, etc.; (2) Use gravitational field as the initial field and apply horizontal boundary loading based on results of previous related researches; (3) Adjust physical parameters and boundary conditions to make the simulated shell surface stress directions and value close to the in-situ stress measurement results as possible, and eventually obtain the current Chinese land shallow stress field.