Zhang, Hui (PetroChina) | Wang, Lizhi (Schlumberger) | Wang, Zhimin (PetroChina) | Pan, Yuanwei (Schlumberger) | Wang, Haiying (PetroChina) | Qiu, Kaibin (Schlumberger) | Liu, Xinyu (PetroChina) | Yang, Pin (Schlumberger)
Located at the foothills of Tianshan mountains, western China, the Dibei tight gas reservoir has become one of the key exploration areas in last decade because of its large gas reserve potential. The previous exploration effort yielded mixed results with large variations of the production rates from these exploration wells and many rates are too low to be deemed as discovery wells. Petrophysical properties were excluded as controlling factors because these properties for most exploration wells are very similar. Under the large tectonic stress, heterogeneous natural fracture systems are induced and unevenly distributed in the reservoir, which might be the controlling factor for production. However, due to the limitation of the seismic data quality, quantitative fracture modeling with seismic is not possible for this field. A new method predicting the 3D occurrence of the natural fractures in the reservoir is needed.
In this study, geomechanics-based methods were used to predict the natural fracture systems in the reservoir. The methods started from classification of natural fracture systems based on borehole image and core data into either fold-related and/or fault-related fractures. Geomechanics-based structure restoration was conducted to compute the deformation and the perturbed stress field from the restoration of complex geological structures through time. A correlation was established between the fold-related perturbated stress field and the occurrence of fold-related fractures from wells to predict the 3D occurrence of this type of natural fractures. Meanwhile, the computation of the perturbed stress field around 3D discontinuities (i.e. faults) for one or more tectonic events was conducted by the Boundary Element Method (BEM) until a good match was achieved between the fault-related perturbed stresses and observed fault-related fractures from the wellbore. By using the output from the two methods, the discrete fracture network (DFN) model was constructed to explicitly represent the occurrence and geometry of the natural fracture system in the reservoir in a geological model. A geomechanical model was constructed based on an integrated workflow from 1D to 3D. The fracture stability was then calculated based on the 3D geomechnical model.
Detailed analysis was conducted among the DFN model, the geological model of the reservoir and productivity of the exploration wells, and very good correlation was revealed between the productivity of the exploration wells and the occurrence and geometry of the natural fractures and the structural position of the reservoir.
This study shows that geomechanics-based methods efficiently capture the occurrence of natural fracture systems and reveal the production-controlling factors of the tight gas reservoir. It demonstrates that geomechanics is a powerful tool to support successful exploration of the tight gas reservoir in tectonically stressed environments.
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.
In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
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.
Introduction Of the three permafrost regions, our calculations show Mohe Basin has the thickest hydrate stability (1300 m). This is followed by Qinghai-Tibet Plateau (1200 m) and Qilian Mountain (800 m).
Currently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.
A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.
The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.
The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.
Zhang, Fan (PetroChina) | Yang, Siyu (PetroChina) | Ma, Desheng (PetroChina) | Lv, Jianrong (PetroChina) | Zhang, Qun (PetroChina) | Luo, Wenli (PetroChina) | Zhou, Zhaohui (PetroChina) | Tian, Maozhang (PetroChina) | Cai, Hongyan (PetroChina)
Chemical flooding technique is one of effective EOR (Enhanced Oil Recovery) ways to improve the oil recovery for mature oilfield in China. It is usually applied successfully in low temperature and low salinity sandstone reservoirs, such as Daqing oilfield (45 C, 5,100 mg/L) and in Changqing oilfield (50 C, 4,700 mg/L). However, it is great challenges to develop chemical EOR formulations for the high temperature and high salinity carbonate reservoir. On the one hand, the high temperature and high salinity condition may cause decomposition of the conventional chemical agents with poor long-term stability. On the other hand, the oil types and compositions, rock surface property and pore structure are all different for sandstone and carbonate reservoirs. Therefore, it is necessary and important to development low cost and high efficiency chemical formulations for high temperature and high salinity carbonate reservoirs. In this paper, the betaine surfactant has been synthesized with cheap raw material of fatty acid, and its functional group of hydroxyl propyl sulfo hydrophilic group can improve the heat resistant and salt tolerant abilities; the star-polymer has been developed and the introduction of multi-functional monomer can inhibit the hydrolysis at high temperature and high salinity conditions. The new SP and ASP chemical formulations have been developed, and show good properties for high temperature and high salinity carbonate reservoir.
The introduction and standardization of the use of an axial friction reduction tool by a service company in they Halfaya field for a national oil company has resulted in a significant improvement in drilling efficiency and reduction in operating costs.
The directional application in the Halfaya field in the start of the campaign was challenging for the operator and directional companies. Challenges in terms of high torque, poor tool face control resulting in multiple trips, damaged bottomhole assembly (BHA), and the inability to reach planned total depth (TD) forced the operator to call for alternative high-end technologies. Those technologies, although wellperforming, presented various operational challenges and did not represent a cost-effective solution to the operator.
The introduction of a simple axial friction reduction tool combined with a positive displacement motor assembly showed an immediate and clear improvement to the torque and drag issues and was comparable to the higher end alternative technologies that were not cost effective.
This paper presents how this tool became an essential part of the BHA with an average of 30% improvement on the overall performance. Apart from enhanced drilling efficiency, another major factor contributing to this achievement was at least a 50% reduction in the number of trips required to change the BHA components, resulting in a highly cost-efficient solution. This technology was successful across all well designs.
A holistic and optimization-based approach focusing on tool placement using a special algorithm was conducted in the field for both the buildup and the lateral sections. The performance of the tool was consistent and gradually improved to becoming the standard with motor assemblies completing sections in one run.
By introducing the axial friction reduction tool, there has been more than 100 runs to date over the course of the Halfaya field development that have lead to a massive cost saving for the operator.
Summary Considerable tight oil resources in China accumulate in carbonate rocks. Due to their individual differences, targetoriented seismic characterization is performed from logbased petrophysical analysis and data mining to seismic inversion and quantitative description. The objective of this study is to map tight carbonate reservoir properties and provide technical support to drilling site deployment. Introduction Tight oil resources in China may mainly occur in Triassic, Jurassic, Cretaceous, and Eocene sandstone and Permian, Jurassic, Cretaceous, and Paleogene carbonate rocks; the former has been found in the Ordos, Songliao, Tarim, Sichuan, Bohai Bay Basins, etc. and the latter found in the Junggar, Sichuan, Bohai Bay Basins, etc. (Jia et al., 2012; Du et al., 2014). More than one third of tight oil resources have been discovered to turn up in carbonate rocks.
Yang, Xiangtong (PetroChina) | Qiu, Kaibin (Schlumberger) | Zhang, Yang (PetroChina) | Huang, Yongjie (Schlumberger) | Fan, Wentong (PetroChina) | Pan, Yuanwei (Schlumberger) | Xu, Guowei (PetroChina) | Xian, ChengGang (Schlumberger)
Keshen is a high-pressure/high-temperature (HP/HT) tight-sandstone gas reservoir with reservoir pressure greater than 110 MPa and temperature more than 175°C. The sandstone is hard, with unconfined compressive strength (UCS) greater than 100 MPa. Given the HP/HT nature and natural-fracture systems in the reservoir, with aid of stimulation, many wells produced at a high rate, with the mean value exceeding 500 000 m3/d. In the last few years, many production wells in this reservoir experienced severe sanding issues that contradicted the conventional understanding that sanding would not occur in such hard rock. The sanding wells exhibited large fluctuations of production rate and wellhead pressure, erosion of chokes and nozzles, and eventually major or even complete loss of production. A solution to address the sanding issues was urgently needed because they had caused a major decline in production and resulted in significant economic loss.
Because of the unconventional nature of the sanding issues, the typical sanding-prediction methods dependent on evaluating rock failure were not adequate to reveal the underlying sanding mechanism and develop a viable operational solution. To this end, a new work flow was formulated and applied to this study. The work flow started with detailed data mining on the large amount of drilling, completion, stimulation, and production data of more than 51 wells from this reservoir to investigate possible relationships of drilling practices, completion options, and production schedules to the occurrence and severity of sanding issues. The analysis revealed that downhole flow velocity and production drawdown were the two major controlling factors in the occurrence of sand production. Further geomechanics simulation and particle-migration simulation with a multiphase dynamic flow simulator confirmed that the production drawdown would cause failure of the rock near the wellbore and the gas flow could transport the sand debris to the wellbore and lift it up to the surface. In addition, the fluctuation of production rate was caused by blockage because of the accumulation of sand particles in the wells and production tubing that were flushed out after downhole-pressure buildup.
Using the analysis, the threshold of flow velocity and the threshold of drawdown were identified, and these thresholds can be used in the reservoir management to effectively address the sanding issues.
The experience in Keshen shows that sanding is possible in HP/HT high-productivity sandstone gas reservoirs, even in an extremely hard formation, which overturns some prior conceptions on sanding. The information shared from this paper could attract the attention of those operating similar HP/HT tight-sandstone reservoirs around the world.