Cai, Zhenzhong (Tarim Oilfield Company, PetroChina) | Zhang, Hui (Tarim Oilfield Company, PetroChina) | Yuan, Fang (Tarim Oilfield Company, PetroChina) | Yin, Guoqing (Tarim Oilfield Company, PetroChina) | Wang, Haiying (Tarim Oilfield Company, PetroChina)
The Kuqa depression located in northern Tarim Basin is the second largest natural-gas field in China, however, drilling engineering is faced with extremely complex geological conditions, such as complex structural movement history, complex formation conditions (huge thick gypsum salt rock, and different thickness of alternating sand/shale sequences and conglomerate), abnormal high pore pressure systems and strong anisotropy in situ stress. These complex geologic conditions result in severe wellbore instability problems.
An integrated research was conducted combining geology, geomechanics and drilling engineering to solve drilling problems caused by complex geological conditions. Firstly, geomechanical models are established according to the geological characteristics of different formations to get orientation and magnitude of stress, pore pressure and rock mechanical parameters. Secondly, based on rock mechanics experiments and wellbore information, the geomechanical mechanism research of wellbore instability was carried out under complex geologic conditions. Finally, the geomechanical model, wellbore stability parameters and the mechanism of drilling problems are applied to the drilling engineering design optimizing mud parameters, wellbore structures and trajectory of high deviation wellbore.
It is shown that geomechanical approach can improve wellbore stability and drilling rate. (1) For the uppermost conglomerate formation, according to the experimental study of the failure mechanism of conglomerate, accurate mud density is the key avoiding causing extension fracture around conglomerate grains. (2) The mechanical stability of borehole in alternating sand/shale sequences is good, but it is easily affected by hydration. Therefore, high quality mud properties can be matched with low mud density to maintain wellbore stability and improve drilling rate. (3)The interior of gypsum-salt sequences is divided into six lithologic sections. Based on the detailed analysis of different lithology, an in-situ stress model is established optimizing the mud density to find a balance between creep resistance and preventing from lost circulation. (4)Pay zone belongs to fractured sandstone under strong stress background. It shows strong anisotropy in stress field and rock strength. The mud density window determined by this mechanism can not only maintain wellbore stability and prevent lost circulation, but also protect reservoir.(5)The feasibility of highly deviated well was demonstrated based on geomechanical approach. And the wellbore trajectory was optimized in four aspects: avoiding shallow fracture, maintaining wellbore stability, traversing more effective fractures, and easy fracturing after drilling.
Geomechanical research under complex geologic conditions promoted the recognition of the mechanism of wellbore instability, and optimized the program of drilling engineering. The drilling incidents of formation above salt were reduced by 50% and the non-productive time was reduced by more than 20%. At the same time, this research project also promotes the successful implementation of the first highly deviated wells which provided a new way to further improve the gas productivity in this area.
One of the most important environmental issues of openpit mining is the closure of mine pit lakes. This article from Mining Engineering provides an account by Gerry Stephenson, who was chief mining engineer of Canmore Mines and was instrumental in the reclamation of Canmore Creek Mine pit lakes. With oil and gas facing a talent gap in the wake of the Great Crew Change, the industry finds itself competing for young talent looking for innovative, purpose-driven work. How can energy foster the culture of innovation needed to attract the new workforce, and how does it sell that culture? The updated document offers an introductory overview of the broad topics of oil spill preparedness and response and provides signposting and hyperlinks to a full range of materials from IPIECA and the International Association of Oil and Gas Producers. This paper details the methodology adopted to monitor gas-pipeline leakages using distributed fiber-optic sensing, using an optical fiber as a linear sensor to provide valuable measurement information from all along the fiber itself. It is “one of the world’s largest greenhouse gas mitigation projects ever undertaken by industry,” Chevron said in a news release.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
KS is a tight-sandstone and high-pressure-high-temperature (HPHT) gas reservoir in northwest China. It is characterized by a depth of more than 6000 m, temperature over 175°C, and pore pressure over 110 MPa. Despite the high unconfined compressive strength (UCS) of sandstone, almost half of the wells encountered sanding issues. The sanding wells exhibited low production rate, nozzle and pipeline erosion, sanding up, and even permanent closure. Investigating the sanding mechanism and developing solutions for sanding prevention are urgent needs due to the economic loss of low production.
An integrated sanding study was conducted to investigate the sanding mechanism. The entire sanding process was analyzed, including stress field alteration during production, rock failure, softening, and sand grain migration. First, wells with sanding issues were identified through production characteristics and field observation. After this, analysis of laboratory tests was performed to better understand the tight-sandstone properties, especially UCS, the softening parameter, and residual strength. Based on the tests, an elastoplastic damage model was proposed to delineate rock failure and sanding behavior. Then, a finite element model was built to simulate the damage of a perforation hole with field data, including hole diameter and length, rock stiffness and strength, drawdown, depletion, and so on. More simulation scenarios were performed to investigate the continuous sanding, transient sanding, and water hammer effect. Grain migration in perforation holes and in pipelines was also studied.
It was revealed that shear failure of perforation hole induced by drawdown and depletion was the root cause of sanding problem. Meanwhile, it was also confirmed that erosion and water hammer effect had very limited effect on sanding. Use of the elastoplastic damage model for the simulation of perforation hole failure enabled predicting the sand amount and determining the critical drawdown and depletion for sanding. In the end, an approach to identifying wells with high sanding risk and the key factors behind the sanding were provided, and sanding prevention suggestions were proposed.
The new elastoplastic damage model explains the sanding mechanism in a tight-sandstone reservoir and enables evaluating the sand volume, which has rarely been published previously. Laboratory tests, field observation, and numerical simulation were combined effectively to investigate the sanding issue. By utilizing the model, producers can find the key factors behind sanding issues, prevent sanding with a better production strategy, and avoid the economic loss, which are critical for the long-term exploration and production of this area.
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.
Wang, Jianhua (CNPC Engineering Technology R&D Company limited) | Yan, Lili (CNPC Engineering Technology R&D Company limited) | Liu, Fengbao (Petrochina Tarim Oilfield Company) | Yang, Haijun (CNPC Engineering Technology R&D Company limited) | Yin, Da (Petrochina Tarim Oilfield Company) | Xu, Xianguang (CNPC Engineering Technology R&D Company limited)
Due to the existence of extremely high temperature, high pressure thick evaporite bed and brine layer, Kuqa piedmont structure has been identified as one of the most complicated drilling regions in the world which locates in Tarim Basin of China. In Keshen Block the occurrence rate of high pressure brine invasion during the drilling progress is high up to 56%, and barite in OBM mud is easy to settle under high temperature and longtime static conditions. Therefore, brine invasion and barite settlement are serious challenges for ultra-deep wells drilling in Western China.
Increasing the density of mud is one method to deal with brine invasion during drilling, but lost circulation is easy to be caused. Another method is discharge the brine in batches to reduce the high pressure of brine layer, which requests the higher brine capacity of OBM. In this instance, a new emulsifier used in OBM was compounded to enhance the emulsifying efficiency through the increase the number of hydrophilic group on single emulsifier molecular structure. The experiment results indicated that the ability of OBM tolerance to brine contamination is higher than 60%.
The instrument for evaluating the sedimentation rate of OBM at high temperature (200°C) and high pressure (20MPa) has been developed. The experiment results indicated that increasing RM6 value could improve the stability of settlement.
Well KS1101 encountered lost circulation and high pressure brine layer in the same horizon, the safety density window of the drilling fluid is almost zero. Thus, the method of brine discharge in batches was used to reduce the brine layer pressure to ensure the drilling safety. A total of 1129.98m3 brine was discharged by 64 times of drainage and avoided the lost circulation. The rheology of OBM is stable, and the brine water capacity of the drilling fluid system is more than 45%. Throughout the drilling process, there was no downhole complex occurred. This OBM system has been wildly used in Keshen Block.
Significant challenges meeting together make Keshen gas field in Kucha foreland basin become unique from geosciences, engineering and economics points of view. These challenges generally link to harsh geography, super deep (>6500m TVD), thick conglomerates (up to 3000m), heterogeneous salt-gypsum laminations (up to 2000m), complex thrust-nappe structure, HTHP, and ultra-tight (matrix permeability < 0.1 md). This paper gives a comprehensive review how the geoengineering Long March assists to successfully develop this field.
A geoengineering team was established to persistently attack on this world-class championship with high-level planning since 2012. Specific research and development of engineering technologies and solutions for data acquisition, drilling, completion, stimulation, testing and production and studies were taking place in parallel. To ensure seamless integration from geosciences and engineering to operation, a five-year geoengineering study was proactively and progressively executed which includes four major steps with respective objectives including 1) understanding fluid distribution and producibility, 2) well production breakthrough and enhancement, 3) optimization of well stimulation and economics, and 4) optimization of field management including surprising sanding problem.
It was recognized three elements and their interactions are critical for production enhancement which are natural fracture (NF) characteristics, production controlling mechanism, and stimulation optimization under super deep, HPHT and extremely high stress conditions. The bottleneck for study was poor seismic quality due to super depth, pre-salt, and complex thrust-nappe structures. Hence the team established comprehensive methodologies with iterative improvements to overcome this bottleneck. Using regional structural geology, outcrops, cores, images and logs as inputs, structure restoration and geomechanics simulators were combined to perform structure restoration, paleo-stresses, and in-situ stresses and eventually 3D NF prediction. To understand production mechanism, analysis of geological and geomechanical factors, NF and stress relationships, single parameter and multiple variables, and transient and production performance were integrated. Big core studies were conducted to understand fracability, NF and hydraulic fracture (HF) interactions, and selections of HF fluids. Based upon, a stimulation optimization approach was implemented which included engineered completion designs, HF modeling and parametric studies, post-frac analysis and optimization, and time effects through high-resolution coupled geomechanics and reservoir simulation. All efforts with evolving knowledge were eventually developed as an interactive expert system to guide systematic stimulation optimization, sanding management and development optimization.
With increasing understanding of reservoir, and implementing innovative solutions, it was enabled to drill wells at optimal locations with less time, simplified well configuration, and less constraints on stimulation and production operations. By 2017, well construction time was reduced by half, natural productivity of wells was doubled, productivity after stimulation was tripled, and overall cost of wells was largely reduced. The success achieved would boost confidence and lighten on development of other challenging fields.
Shuai, Shichen (PetroChina Tarim Oilfield) | Zhang, Xinlei (PetroChina Tarim Oilfield) | Ma, Tengfei (PetroChina Tarim Oilfield) | Zhao, Yuanliang (PetroChina Tarim Oilfield) | Guo, Qingbin (PetroChina Tarim Oilfield) | Chen, Jichao (Schlumberger) | Fan, Zhaoya (Schlumberger) | Bi, Bo (Schlumberger) | Yang, Lei (Schlumberger)
KeShen block at Tarim basin is one of the most important gas reserve for PetroChina. The single well gas production at KeShen area can be as high as million cubic meters per day. However, the complex geology settings of KeShen area lead to significant difficulties on the engineering aspects from the drilling, logging, completion to testing. The reservoir is below a salt layer, having a nature of high pressure and high downhole temperature. Often, the reservoir section must be drilled with 6in hole or even smaller hole size. The combination of challenges: ultra-deep (more than 6000 meters), high temperature, high pressure and slim hole cause the testing operation usually lasts for a few months in time and costs a few million dollars, which is extremely expensive for a land well. Mini-DST with formation testers therefore is considered as an alternative option to providing the necessary fluid, pressure and productivity information.
The main target of the reservoir sand is tight, the permeability is ranging from 0.01 mD to 1mD. Mini-DST operation was not feasible in such challenging environment with the conventional formation testers in the market. A recent introduced new equipment, named 3D radial probe fitting for the slim hole allow a feasibility trial for mini-DST in KeShen area. By the design, the new equipment can work in 6in open hole and provide max. 8000psi pressure drawdown capability. A simulation work has done to confirm this high drawdown can enable the gas flow from the formation to accomplish the testing.
A numerical approach, which integrating all the logging data set and the mini-DST result, is conducted to understanding the production potential of the well. A single well numerical model is created using the logging data, the permeability is carefully calibrated with the mini-DST interpretation, the hydraulic fractures can also be added to the model for feasibility study on well stimulation.
In the last 2 years, multiple wells were selected in KeShen area to do the mini-DST with the new 3D radial probe, the results were very promising. The mini-DST done in the trial wells provide high quality PVT gas samples, high quality pressure transit data for permeability interpretation. The numerical production evaluation also matches very well with the DST result later for comparison. The whole mini-DST operation takes only a few days including conditioning the mud, which is a signification saving on the time and cost. All the cases in these wells will be reviewed and discussed.
With this confirmative result of the work, Mini-DST becomes the first option to test a well at KeShen area if the well condition allowed to reach optimal balance between the data obtained and operation cost.
Zhang, Dujie (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation • Southwest Petroleum University) | Kang, Yili (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation • Southwest Petroleum University) | You, Lijun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation • Southwest Petroleum University) | Li, Xiangchen (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation • Southwest Petroleum University) | Li, Jiaxue (CNPC Tarim Oilfield Company) | Chen, Yashu (Missouri University of Science and Technology)
Cretaceous Bashijiqike ultra-deep tight sandstone, the main pay zone of Keshen gas field in Tarim Basin, has characteristics such as huge buried depth (6500 m ~ 8000 m), ultra-low matrix permeability and well-developed natural fractures. Due to lacking of a thorough research on the formation damage mechanism, there is no corresponding formation damage control method. And that's why this reservoir is suffering from severe formation damage. In this paper, the multi-scale characteristic of the reservoir space and seepage channel was described firstly. Then, a series of experiments were carried out to determine the multi-scale damage mechanisms, including the fluid sensitivity damage of matrix and fracture, the phase trapping damage of matrix and fracture, the loading capacity and the dynamic damage of fracture induced by drilling fluids. Then, the multi-scale formation damage mechanisms were summarized. Results showed the gas reservoir are characterized by typical multi-scale structures, i.e. micro-nano pore-throat and multiscale natural fractures. Severe salt sensitivity damage, alkali sensitivity damage and water phase trapping damage were the main damage mechanism of micro-nano pore-throat. For micro-fracture (aperture ≤ 100 μm), the dynamic damage degree induced by drilling fluids can reach up to 60.01 %. For Mesoscale fracture (aperture > 100 μm), lost circulation induced by inadequate loading capacity of drilling fluids was the main damage mechanism. Then, a complete multi-scale approach for damage control was proposed: ① Using oil-based drilling fluids to inhibit the fluids sensitivity damage and phase trapping damage of micro-nano pore-throat and natural microfracture; ②Optimizing the solid particle size distribution of drill-in fluid to reduce the dynamic damage degree of micro-fracture induced by drilling fluids; ③Adding acid soluble temporary plugging materials while drilling to prevent lost circulation. According to the proposed approach, the total production of the test well was 94 × 104 m3, which is much higher than that of non-test wells. This research provides a detailed case of forming the multi-scale approach for damage control based on the multi-scale formation damage mechanisms. This method is practical and useful, and it has important guiding significance to develop the ultra-deep fractured tight gas reservoirs efficiently.
The Kenshen tight gas field, located on the northern margin of the Tarim basin, western China, has extreme reservoir conditions of an ultra_depth reservoir (6500 to 8000 m) with low porosity (2 to7%), low matrix permeability (0.001 to 0.5 md), high temperature (170 to 190°C), and high pore pressure (110-120 MPa). Those conditions result in high completion costs and a significant difference in individual well production rates; with only one-third of wells drilled meets expectations. Previous studies focused on natural fracture(NF) and attempted to classify reservoir qualities based on the density of NF. Unfortunately, some NFs were closed or cemented by clay or calcite, and it is hard to distinguish open NF from closed NFs using well images in oil-based mud, which is widely used in this tight gas field for reservoir protection. Thereby, no positive correlation between NFs density and productions has been identified, even with the same stimulation treatment.
In this study, a comprehensive geological study was conducted to find a new way of characterizing the effectiveness of NF. First, the initial and development stages of NFs were recontructed through a tectonic activity study. Two stages were detected and showed different strikes. Second, petroleum system modeling technology was applied to simulate source rock maturation and gas migration, which revealed that gas generated in the Jurassic source rock migrated to the Cretaceous reservoir formation through faults activated in the same period as the late stage of NFs development. NFs developed earlier were closed or cemented by calcite of later deposition; those at late stage were open and effective for gas charge. Also in this study, Advanced analyses of borehole images indicated an alternative way to delineate NFs developed at different stages using geometry (i.e, crossed NFs shall include those ones developed at later stage). Parallel NFs with its development unidentified can be classified through the intersection angle of fracture strike and maximum stress direction. The smaller the intersection angle is, the easier it is for stimulation and alos the higher for the well production. Based on this study, we have divided reservoirs in the study area into three classes: class 1, reservoir with crossed NFs; class 2, reservoir with fractures of small intersection angle; class 3, reservoir with fractures of large intersection angle. This innovative reservoir classification through NF geometry is currently used in the field to determine formation stimulation method. Class 1 reservoir can benefit from acidizing alone with low completion cost. Class 2 reservoir of should be hydraulically fractured with acid. Class 3 reservoir of should be fractured with sand and proppant sand to achieve economical production.
Reservoir classification with NFs geometry had been applied successfully to guide stimulation design in the Keshen tight gas reservoirs. It is a practical and feasible way to choose the most appropriate stimulation treatment method to optimize well performance and avoid restimulation to reduce costs for this extreme type of tight gas field in western China.