bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Contributing Factors of Stimulation Design to Incremental and Long-Term Productivity in Bakken Play
Authors: Zhou Fujian , Xue Yanpeng , Qu Hongyan , Qin Xiaolun 
Published: November 2015

Abstract
The combination of horizontal drilling, multistage completion and hydraulic fracturing has been the key factor for the successful development of the Bakken play. This dominant status reflects in two aspects: the enhancement of well production, making stripper well even dry well valuable for industrial development, and the effect of long-term flow conductivity on the ‘sustained yield’ of well. This paper quantitatively analyzed the stimulation design factors and their interactions contributing to incremental and long-term productivity of horizontal wells in Bakken respectively for different geologic environment.
Data from more than 1000 wells located in the Bakken Central Basin area containing production and stimulation design have been collected from the Premium Services of North Dakota Industrial Commission (NDIC) website and the FracFocus.org. Wells were grouped and analyzed by similar water cut based on cumulative production for the normalization of variation in geologic heterogeneity. Response surface methodology (RSM) was applied as the methods of quantitative analysis to determine the contributing factors and their interactions. In this study, 2-month and 12-month cumulative oil production per perforated length were used as the indicators of incremental productivity and long-term productivity respectively.
The data are divided into three reservoir-homogeneous groups according to different water cut range and a separate slickwater fracturing group. The effects of stimulation design factors and their interactions on the incremental productivity and long-term productivity were investigated. Results indicates that among all the factors, perforated length, proppant/perf length, water/ perf length, percentage of ceramic are the most contributing factors of stimulation design to incremental and long-term productivity. Different group are influenced by different combination of contributing factors. Most groups share the same significant interaction between perforated length and water/ perf length, as perforated length increases and water/ perf length decreases meawhile, the cumulative oil production per perforated pength climbs rapidly, with the amount of other design factors fixed.
Previous similar analysis focused on 30, 60 and 90-day cumulative production with smaller data volume to generate well performance metrics for the lack of enough wells. This paper utilized the larger data set with longer production time span and analyzed the stimulation design factors contributing to incremental and long-term productivity of horizontal wells in Bakken respectively. These results are more valuable for optimization of stimulation design in the Bakken play and similar reservoirs faced with dynamic and changing oil market.
A Novel Thermal-Resistance and Salt-Tolerance Gel with Low-Concentration Crosslinkers for Water Shutoff in Tahe Oilfield
Authors: Chen Lifeng , Zhang Guicai , Ge Jijiang , Jiang Ping , Zhu Xiaoming , Lin Yang , Han Shengxia 
Published: November 2015

Abstract
Tahe Oilfield is an important oilfield of Sinopec in Northwest China. The reservoir temperature is up to 130°C, and the salinity is as high as 223,000 mg/L. Water production problem is getting worse along with the continuous water injection, but no gels can be successfully applied for water shutoff due to the hostile reservoir condition. Hence, obtaining a thermal-resistance and salt-tolerance gel is more and more important for Tahe Oilfield to decrease the unwanted water production.
In this paper, a novel gel system with low-concentration organic crosslinker was developed for water shutoff in Tahe reservoir condition. The gel is based on the polyacrylamide/2-Acrylamido-2-methylpropane sulfonic acid (AM/AMPS) copolymer, and it employs hexamethylenetetramine, resorcinol and phenol as the crosslinkers. Addition of n-hydroxyethylethylenediamine as an anti-syneresis agent increases the gel stability, and the ethylenediamine can be as a crosslink delay agent to increase the gelation time. The system was mainly studied for effects of concentration of polymer and crosslinker on gel stability, and the thermal-resistance and salt-tolerance mechanism of the gel was investigated by the thermostability and scanning electron microscope (SEM) measurements.
The strong gel can be obtained when the total crosslinker concentration is 800 mg/L, which is an ultralow low concentration for the crosslinker used in the gel for water shutoff. The gelling solution with a few tens of centipoise viscosity can be pumped with low pressures to effectively seal problem water zones thereby reducing operational costs and increasing recovery. The gel syneresis (defined as the decrease in the gel weight at a given time relative to the initial gel weight) is only 12.5% after the heat-treatment under the difficult environment condition (temperature=130°C, salinity=223,000 mg/L) for 100 days. Core flooding results have illustrated that the plugging efficiency of the gel, which has been heat-treated for 100 days under the above difficult condition, is more than 90%. The thermal treatment experiment shows that AM/AMPS is difficult to be degraded, and the SEM measurement indicates the heat-treated gel still has uniform grid structure, which may be the main reasons for the remarkable stability of the gel under high-temperature and high-salinity condition.
The successful development of the novel gel with low-concentration organic crosslinkers not only reduces the production costs and the pollution to the environment, but also provides reference and guidance to obtain the methods to improve the gel stability under harsh conditions. By impeding water production, the gel developed here can be used to delay excess water influx and thus premature abandonment (or installation of expensive lift equipment), thereby extending the life and reserves of oil wells in Tahe Oilfield.
Effect of Mud Filtrate Invasion on Measurement of Formation Pressure and Determination of Gas-Water Contact Depth in Tight Gas Reservoirs
Authors: Bahrami Nick , Byfield Russell , Hossain Mofazzal , Pourabed Hamidreza 
Published: November 2015

Abstract
Formation testing is one of the key steps of reservoir evaluation and provides essential information about static pressure of reservoir layers, water-hydrocarbon contact depth and hydrocarbon volume in place. In a gas bearing zone drilled with water-based mud (or oil-based mud), the pressure measurements in the gas zone are influenced by mud filtrate (liquid) invasion effect. The formation tester measures the pressure of filtrate, which is less than the reservoir pressure for the gas phase by an amount equal to the capillary pressure.
In tight formations, a reliable determination of pressure gradient is challenging due the low reservoir permeability, weak mud cake build-up on the wellbore wall, continuous invasion of the mud filtrate from the wellbore into the reservoir, and by the effect capillary pressure that causes mud filtrate to be imbibed into the reservoir. Thus, the measured pressure in tight reservoirs may be different than the actual formation pressure as a result of the supercharging effect.
This paper examines the estimation of the true formation pressure in tight gas reservoirs using numerical simulation approach and evaluates the effect of filtrate invasion and capillary pressure on the measured formation pressure and the gas-water contact depth. The results highlighted that due to the mud filtrate invasion into a gas zone in a tight reservoir, the measured pressure may be less than the actual reservoir pressure, and also pressure gradient may be over-estimated. Therefore in tight gas reservoirs, the under-estimated reservoir pressure and over-estimated pressure gradient may make the measured water-gas contact depth to be different than the actual water-gas contact depth.
Experimental Study of Controlling Factors of the Continental Shale Matrix Permeability in Ordos Basin
Authors: Qu Hongyan , Zhou Fujian , Xue Yanpeng , Pan Zhejun 
Published: November 2015

Abstract
Matrix permeability could be a key factor controlling shale gas production from matrix to micro fractures and further to hydraulic fractures in Chinese shales due to the low porosity and permeability, affected by its unique geochemistry and geology settings including the Total Organic Carbon (TOC) content, mineral compositions, pore structure, and deposition environment. This paper aims to study the controlling factors of the matrix permeability in the continental shale formation, Ordos, China, through modified laboratory measurement mothod.
In this work, nine shale samples were collected from three wells in Chang 7 member, Yanchang continental formation, Ordos Basin, China, crushed at in-situ water saturation and sieved to certain size (20/40 mesh). Matrix permeability of these samples was measured with modified Pressure-decay method and compard with the results with Pulse-decay method. The reasons for the discrepancy of these results with different methods were analysed. Moreover, the effects of geochemistry and geology factors on matrix permeability were investigated by grouping these crushed samples according to the variation of TOC, mineral compositions and deposition depth. The relationships between shale matrix permeability and TOC as well as depth were established respectively. Furthermore, the effects of other factors such as mineralogical compositions and pore structure parameters were studied through the Scanning Electron Microscope (SEM) and X-ray diffraction (XRD) analysis.
The results show that the shale matrix permeability measured by the Pulse-decay method is generally up to two orders of magnitude higher than that by the Pressure-decay method due to the presence of the natural or artificial micro fractures. In addition, the geochemistry and geology parameters including the TOC, mineral compositions, pore structure and deposition environment have significant effects on the shale matrix permeability. Matrix permeability in Yanchang shale formation is strongly related to TOC and the mineral compositionand even at the similar depth, porosity and matrix permeability are different due to the variation of TOC as a result of geological heterogeanity. TOC in Yanchang formation varies considerably in the range of 1.8 wt % to over 11 wt %, resulting in significant changes in matrix permeability ranging from 0.02 nD to 10 nD, resulting from the influence of the organic matter and clay minerals on total pore volume based on the result of SEM and XRD analysis. The accurate measurement of matrix permeability is important for computer simulation modeling of long term shale gas production.
Selection Criteria and Evaluation Technology for Casing Used in Shale Gas Wells in China
Authors: wang Jiandong , rao Xiaodong , han Lihong , li Yufei , zhou lang , lu Xiaoqing 
Published: November 2015

Abstract
The fracture interventions were operated in 144 segments of 24 wells in CNPC Changning and Weiyuan shale gas fields. Among these fracture interventions, 10 wells happened different degree of casing deformations, and one well had casing connection jump-out. So the casing failure rate reached 45.8%. The casing failure modes included casing deformations in reservoir fracturing sections which occurred following hydraulic fracturing, blockage during drifting and bridge plug process, casing connection jump-out, and annulus pressure buildup between casing and tubing during well shut-in. A comparative study was performed on the geological conditions, well completions, and fracturing pressure for the shale gas fields between China and North America. The study shows significant challenges for shale gas exploration in China, with severe conditions such as high reservoir temperature at 150 °C, high gas pressure at 60MPa, and discontinued in-situ stress in the faults where the maximum horizontal stress is significantly higher than the overburden pressure and the minimum horizontal stress. Standard T&C connections were used for casing strings. Based on analysis of casing installation, fracturing and production process, it was concluded that the conventional tubular design approach could not be applicable for the shale gas applications in China. The primary cause for local casing deformation can be related to the formation shear loading, resulting from multi-layer fracturing process. Casing joint used premium connection of gas-seal. API Spec 5CT (2010) material transverse impact toughness couldn't meet fracturing needs in practice. Coupling often cracks and then jumps out. This paper presents Finite Element Analysis (FEA) of casing strings subjected to shear loading and transverse impact toughness of resistance to crack initiation on fracturing. Based on the FEA study, the performance requirements and evaluation criteria for shale gas production casing were developed. This paper also presents an example where the proposed methodology was used to analyze and evaluate casing performance, and ensure the safety of the well operation.
Integrated Production Modelling for CSG Production Forecasting
Authors: Shields A.. , Tihonova S.. , Stott R.. , Saputelli L. A , Haris Z.. , Verde A.. 
Published: November 2015

Abstract
An Integrated Production Modelling process is presented that is used to automate CSG (Coal Seam Gas) production forecasts from reservoir to sales. This involved incorporating type curves representing future reservoir performance into a hydraulic model of the surface network. One of the key challenges was to convert time-dependent decline curve forecasts into time and pressure-dependent reservoir-well models suitable for Integrated Production Modelling process. Results are compared to other methods with reduced simulation time, improved accuracy and scenario analysis.
This innovative approach used a combination of techniques to incorporate type curve based reservoir models into two large integrated production models. The first model consisted of 250 wells and a single compressor station and the second model consisted of 500 wells and multiple compressor stations. Different techniques were applied for wells that were pre or post dewatering and incorporated into a surface network modelling tool. This allowed production forecasts to be generated automatically for the single compressor station model and semi-automated for the multiple compressor station model whereby the system was solved to meet demand or to maximise production taking into account constraints.
Type curve data was converted to a ‘tight gas’ reservoir model which showed a good match for wells post dewatering but not for wells that were still inclining. A combination of proprietary scripting in a network simulation program and macro code in Excel were used to handle system constraints optimisation. The time taken to run each scenario reduced significantly as the restriction moved from a human to the amount of computing power. Accuracy and repeatability of results also improved due to models being setup and solved in a consistent manner, thereby removing discrepancies associated with manually driven models. This allowed for more scenarios to be modelled in the time allocated to the production forecasting processes allowing for improved analysis and decision making.
Previously type curved based reservoir models could not be solved by a surface network modelling tool automatically without human intervention. This was not possible due to the size and complexity of the surface network and because of the lack of time and pressure-dependent reservoir-well models suitable for Integrated Production Modelling process. The process outlined in this paper overcame this challenge.
Produced Gas Re-Injection Trial for a Coal Seam Gas Field
Authors: Thomas Oliver 
Published: November 2015

Abstract
A trial was conducted by Origin Energy to study the feasibility of re-injecting produced coal seam gas (CSG) also known as coal bed methane (CBM) back into depleted coal formations. The trial specifically set out to identify any practical limitations of re-injecting gas as a means of keeping wells online during downstream process interruptions. This included identifying any changes to coal permeability, evidence of gas re-adsorption to the coal and operational learnings with the injection system. The trial met its objectives in that analysis indicated a high likelihood of injected gas re-adsorbing to the coal matrix, and there were no significant operational issues.
The trial was conducted using two injection wells converted from production wells in a depleted, high permeability area of an Australia Pacific LNG gas field operated by Origin in Queensland, Australia. Injection periods were conducted at different rates, with data recorded from injection wells and offset wells. Analysis included pressure transient analysis (pressure build-up and injection fall-off tests), numerical simulation modelling, nodal analysis, and material balance modelling.
Gas injected into Well 1 appeared to migrate away from the well, with an increase in production rate observed at an offset production well. Interpretation of down-hole pressure data indicated likelihood that Well 2 was injecting into a closed reservoir compartment. Numerical simulation modelling indicated a high likelihood that injected gas was re-adsorbing to the coal in this area. Numerical simulation, nodal analysis and material balance modelling were used to estimate maximum injection rates and storage volumes for further injection. Groundwater monitoring bores were also monitored for changes in pressure and water chemistry, to validate containment of injected gas within the coal reservoir.
Hydraulic Fracture Design Optimization in Low Permeability Coals, Surat Basin, Australia
Authors: Kirk-Burnnand E.. , Pandey V. J. , Flottman T.. , Trubshaw R. L. 
Published: November 2015

Abstract
Modern hydraulic fracture treatments are specifically designed to unlock reserves from particular rock types, especially in unconventional reservoirs. Progressive improvements in fracture design can be critically informed by post stimulation pressure analysis, yet this process is often overlooked. This paper documents the evolution of fracture designs by successively incorporating post-stimulation pressure analyses after major design changes that ultimately led to the design-optimization of fracture treatments in low permeability coals. The coals under context are the Walloons coal measures in Jurassic to Cretaceous aged rocks in the Surat Basin of southeast Queensland, Australia.
Significant challenges are faced in stimulating the Walloons coal measures due to their thin-bedded nature, that range from 0.2 to 3.0 m [0.66 to 9.8 ft] in thickness and, which are also inter-bedded with low permeability siltstones, minor sandstones and carbonaceous shales. Net coal thickness is 20 to 40 m [98.43 to 131.23 ft] in a gross sequence of 300 to 400 m [948.3 to 1,312.3 f] thickness. Reservoir complexity is further impacted by lateral continuity variations of coals, which generally have a high Poisson’s ratio (&gt;0.32). In particular where coal reservoirs display low permeability, understanding and implementing reservoir beneficial fracture treatments becomes pivotal to successful well performance.
Modification of fracture designs during the fracture campaign included changing key parameters such as fluid types, pump rates, proppant loading and gel concentration. Both, the treatment and the calculated bottom-hole pressures, were evaluated using 3D fracture models, supplemented by an array of diagnostics such as surface tilt-meters, diagnostic fracture injection tests, micro-seismic monitoring and tracer logs as well as log derived stress models. The results of these diagnostics helped shape the design changes implemented throughout the campaign and has influenced designs for future trials also. Ultimately, it was observed that the treatments that were pumped using low gel loadings in conjunction with high proppant concentrations, and at relatively lower rates, resulted in better well performance.
This paper presents the design and treatment evaluation process and also provides an insight into the progression of fracture design and subsequent treatments which were successful in overcoming reservoir complexities. The outlined approach can be used to refine hydraulic fracture treatment designs in similar complex reservoirs in Queensland, with worldwide applicability.
Optimization of Horizontal Well Spacing and Transverse Fracture Stages for a Thinly Interbedded Tight Sand Reservoir Onshore Australia
Authors: Younessi Ahmadreza , Rahman Khalil 
Published: November 2015

Abstract
Hydraulic fracturing optimization requires addressing numerous challenges for various reservoirs. The proposed paper presents a case study of a thinly-interbedded tight sandstone reservoir with a very low net to gross ratio in a field, onshore Australia. A geomechanical model was developed for hydraulic fracturing optimization. The low contrast in stress and rock mechanical properties between the reservoir and bounding formations posed a challenge to achieve a fracture that was confined to the pay zone, and particularly one that avoided fracturing the underlying water-bearing zone. Optimization modelling showed that the oil flow rate increased proportionately with fracture length and conductivity up to certain threshold values, above which the production benefit diminished. An injection schedule was optimized for production using a proppant and a fracturing fluid both suitable for the reservoir conditions to achieve the optimum or near-optimum fracture length and conductivity, efficient proppant transport, and confinement of the fracture above the water-bearing zone. Production prediction through the optimized fracture design in a vertical well showed a potentially uneconomic recovery. Multi-stage fracturing of a 1,500 m horizontal well was investigated as an alternative completion scenario for which the number of transverse fractures was optimized. The spacing between such horizontal wells was also investigated and optimized based on efficient drainage that could be achieved by the horizontal well with the optimum number of transverse fractures. Optimally spaced horizontal wells with an optimum number of transverse fractures were found as the most recoverable development strategy; use of injection wells for lateral sweeping and pressure maintenance, and artificial lift is likely to increase recovery further whereas infill wells are likely to be necessary for incremental production.