bluuebunny/crossref_metadata_2025 huggingface dataset:
PENDEKATAN FILSAFAT HERMENEUTIKA DALAM PENAFSIRAN AL-QURAN: Transformasi Global Tafsir al-Quran
Authors: Mufid Fathul
Published: November 2015

This essay will describe the transformation process of the interpretation of al Quran from the literal perspectives towards hermeneutics interpretations method, in a line with the recent globalization changes. Globalization is an era after modern where the world like a small village (global village), which makes interaction among countries, civilizations, religions, and cultures become more intens, fast and easy. This golbal changes is a medium which influencing cultures, countries, civilizations, and even religions aspects. Al Quran intepretation method which has been used by classical scholars stress more on the literal approach (tahlili) was considered to be irrelevant to answer and respon the current human problems in this globalization era. The advanced of the global information technology has brought positive impact for human life to fullfil their live needs. However, on the other side, golbalization brings negatives effect as well. For instance, since the information centers are controlled by advanced secular  countries, the understanding of the Al Quran from various dimensions has shift and lose its function. These negatives effects are unavoidable for moslems which getting more influence on their religius life, including their understanding on the Holly Quran. Therefore, whether like or not, scholars in the intepretaion fields should adjust and inovate according to the current needs and trends using heurmenutics approach. Heurmenutics is a classical text critics method  which is used to understand al Quran that contains God’s messages that should be understood, and used in our life practically and empirically.
MANAJEMEN QUR’ANI MENUJU KEMANDIRIAN UMAT
Authors: Mulyono Mulyono
Published: November 2015

Al Quran contains conceptual ideas related to theology (aqidah), worship, human relation (muamalah), science, philosophy, and many others. It includes some regulations to manage the attitude of human beings, both as individuals and as social creatures, for the sake of achieving better future in the world and in the eternal life (akhirat). It is no wonder that al-Qur’an also brings up some basic concepts of management, which are academically acknowledged as al Quran–based Management or Quranic Management.

As this paper mainly concerns, al Quran encompasses several verses explaining the concepts of management. It requires Moslems to be autonomous society by planning any actions, preparing and positioning qualified human resources, occupying the assets as well as possible, consolidating the branches, and operating the wealth into beneficial activities. Such an ideal can be straightforwardly accomplished by performing the Quranic Management principles, which comprise amar ma’ruf nahi mungkar, truth, justice, and amanah (trustworthiness).
ISLAM DI PAPUA BARAT: TRADISI DAN KEBERAGAMAN
Authors: Wekke Ismail Suardi
Published: November 2015

It was well known that Papua as large population of non muslim society. In fact, muslim already establish their community on 1512. Therefore, it is a need to explore how the existence of muslim in West Papua province nowdays. This research was applied qualitative approach which is grounded theory. In finding data, observation and in-depth interview were conducted. In addition, the main instrument was researcher itself, and then other instruments are observation sheet and interview guidance. This research shows three things, they are leadership and tradition, religiousity and diversity, and learning spirit. Those kinds of main findings means that muslim in the region not only preserve their tradition but also try to maintain the harmony to other religions. This attitude did not arise spontaneously, there was a long history of co-exist with the others as a family.
TEORI MAQASHID SYARI'AH PERSPEKTIF IBNU ASHUR
Authors: Toriquddin Moh.
Published: November 2015

Ibnu Ashur is a contemporary figure of maqasid syariah which born in Tunisia. He was complement and continues of maqasid concept which previously created by  imam al Shatibi, al Ghazali, Izzudin bin Abd. Salam, Ibnu Taymiyah, Ibnu Qayyim al Jauziyah, and another. By Ibnu Ashur, maqasid syariah easily practice in contemporary problems so that Islamic law still suitable with period or be up to date or in Arabic we can call salihun li kulli zaman wa al makan. There are few reform used by Ibnu Ashur in maqasid syariah for instance all discipline law are good characteristic is muamalah (transaction) or ibadah (religious service), all has illat (reason). For implementation maqasid theory by three steps: maqam khitab al syar’iy (situation dan condition of khitab syar’iy), al tamyiz baina al wasilah wa al maqshud (differentiate between infrastructure and purpose), istiqra’ (induction). Maqasid syariah theory by Ibnu Ashur however, globallly based on maqashid al ammah and maqashid al khasah. However, foundation thought for decide maqasid using by fitrah, maslahah, and ta’lil. For knowing something that has benefit or not, he was classified it by three categories benefit for community, benefit for group or person, and realize necessary.
A Novel Polymer-Assisted Emulsified-Acid System Improves the Efficiency of Carbonate Matrix Acidizing
Authors: Zakaria A. S. , Nasr-El-Din H. A.
Published: November 2015

In highly heterogeneous carbonate reservoirs, several acid systems were used to enhance acid diversion during matrix-acidizing treatments. Viscosified acid with polymer increases the viscosity of the acid system to improve the wellbore coverage. However, the injection of such acid at low rates had a negative effect on the spending rate and starts filter-cake formation, which inhibits the wormhole growth. On the other hand, relatively low-viscosity emulsified acid is diffusion-retarded, which makes it an effective wormholing agent at the low injection rates that occur, for example, in low-permeability or damaged formations. None of the studies in the literature addresses an acid system that uses both advantages.

The objective of this work was to investigate the behavior and the performance of a new acid system, polymer-assisted emulsified acid, as a self-diverting acid by conducting viscosity measurements through coreflood study and acid-diversion experiments. The system was 15 wt% hydrochloric acid (HCl)-gelled acid emulsified in diesel with a 70:30 acid/diesel volume ratio.

Coreflood experiments with Indiana limestone were conducted at 230°F at different injection rates, and the core samples were imaged with a computed-tomography (CT) scan technique after each coreflood experiment. Also, 0.5 pore volumes (PV) of the polymer-assisted emulsified acid was injected to assess the effect of the acid on the permeability of the cores before breakthrough. Finally, two acid-diversion experiments at 1 cm3/min were conducted into pairs of low- and high-permeability cores to test the effect of polymer concentration in the acid internal phase on diversion.

The viscosity measurements and acid-diffusivity measurements showed that increasing the polymer concentration in the acid internal phase of the emulsified acid from 0 to 1.5 vol% significantly enhanced the viscosity of the emulsified acid and reduced the diffusion coefficient by one order of magnitude. Coreflood results showed that the polymer-assisted emulsified acid was an effective wormholing fluid at low injection rates while maintaining the high viscosity of the acid system for zonal coverage.

Also, it was shown that the emulsion/polymer retention was the main source for permeability damage. However, flowback with mutual solvent removed any remaining damage, and permeability enhancement was achieved.

Acid-diversion experiments are presented that show the self-diverting ability of the polymer-assisted emulsified acid into the low-permeability cores.
Successful Application of Hot-Water Circulation in the Pelican Lake Field: Results and Analyses of the E29 Hot-Water-Injection Pilot
Authors: Duval Kirk , Gutiérrez Dubert , Petrakos Dino , Ollier Pierre , Johannson Darren
Published: November 2015

The Pelican Lake field in northern Alberta (Canada) is home to the first successful commercial application of polymer flooding in higher-viscosity oils (i.e., greater than 1,000 cp), which has opened up new opportunities for the development of heavy-oil resources.

The field produces from the Wabiskaw “A” reservoir, which has thin pay (2 to 6 m) and exhibits a significant viscosity gradient across the field, with oil viscosities as low as 600 cp in the existing waterflood and polymer-flood areas to more than 200,000 cp in the current undeveloped “immobile” area. This unique geological feature limits the application of chemical injection to the less-viscous areas of the field and calls for different methods for the heavier accumulations.

As a first step to develop alternative technologies capable of recovering oil from heavier areas of the field not ideal for polymer flooding, a Cenovus-designed hot-water-injection pilot began implementation in June 2011. The hot-water-injection scheme was applied to a transition area in which dead-oil viscosity ranges from 3,000 cp to approximately 15,000 cp. It consisted of one horizontal producer supported by two horizontal hot-water injectors, with an injector/producer distance of 50 m for both injectors, and three vertical observation wells equipped to monitor pressure and temperature between one injector and the producer.

The pilot was operated in three phases. The first phase consisted of a 6-month primary-production period to obtain a baseline of the pilot performance before hot-water injection. The second phase consisted of hot-water injection through the edge injectors. The third phase consisted of hot-water edge injection accompanied by hot-water circulation in the production well as a means to stimulate oil production. One of the features of this stage is the use of an insulated coiled tubing (ICT), which delivers hot water continuously to the toe of the producer and allows continuous stimulation and uninterrupted oil production.

This paper describes the mechanical components of the pilot and discusses the results obtained with an emphasis on the hot-water-circulation process, which has proved to be very effective. Oil production increased from approximately 6 m3/d during the flood stage to more than 25 m3/d during the hot-water-circulation stage and has held relatively steady for more than 2 years.

The data captured have been reconciled with analytical and reservoir-simulation models, and results suggest that the technology may help unlock some of the heavier oil accumulations in the field.
Drilling and Completion Optimization in Unconventional Reservoirs with Data-Driven Models
Authors: Holdaway Keith R. , Laing Moray L.
Published: November 2015

We shall discuss the following objectives: the use of Multivariant Analysis (MVA) to identify and classify important performance variables implemented in the hydraulic fracture treatment strategies. We shall discuss field optimization workflows initially performed in the Pinedale asset in Wyoming. Data were collated from multiple fluvial sand layers that aggregate across the anticline structure under study. Initial exploratory data analysis and bivariate analyses fell short of a comprehensive appreciation of the multivariate, stochastic and multivariant nature of this complex heterogeneous system. The MVA approach addressed the complexity "inherent in the data's coincident variation in multiple parameters. Data clustering was used to create different models and assess different parameters. Models were able to identify the relative impact of the most significant variables affecting stage production performance, and develop probability distributions for potential outcomes at different categories of production. A neural network was chosen to evaluate both reservoir parameters as well as variables that are controlled by the operator such as proppant volume and flowback methods."1

"Evaluation was conducted on 195 stages of which 49 were identified as candidates for increase in proppant volume. Through this process the authors identified a need to update the model to include the impact of pressure depletion from down spacing. Even in the absence of accounting for pressure depletion the team experienced excellent results."1

The goal is to design as efficient a completions strategy as possible across the anticline as more wellbores are drilled. Capturing the knowledge garnered from the geological parameters to maximize reservoir contact and the proppant volumes deemed appropriate across each stage of the wellbore, it is feasible to implement a function that identifies the values of operational parameters to maximize production. We can also identify which stages are most productive and shut down those stages that are under performers to reduce operational expenditure.
CO2 Near-Miscible Flooding for Tight Oil Exploitation
Authors: Zhang K.. , Perdomo M. E. , Kong B.. , Sebakhy K. O. , Wu K.. , Jing G.. , Han J.. , Lu X.. , Hong A.. , Chen Z..
Published: November 2015

Tight oil resources have become increasingly important as massive hydraulic fracturing techniques breakthrough. Water flooding is generally applied to tight oil reservoirs; however, the oil recovery achieved by water flooding is quite low. A CO2 miscible flooding process is regarded as a primary enhanced oil recovery (EOR) technique for conventional oil reservoirs as CO2 can extract oil even at a high water cut. Furthermore, many CO2 field trials in low permeability reservoirs have been recorded as successful. As CO2 utilization efficiency drops when formation permeability goes down, CO2 injection in a miscible condition for tight oil exploitation may not be as profitable as that in conventional oil reservoirs.

In tight formations, there exist small pore throats, even at nanoscale. As the confined space in nanopores may shift a phase envelop and lower CO2 minimum miscible pressure (MMP), operating a well in a near-miscible region where pressure is slightly less than MMP as measured in the lab may result in a good chance of miscibility for some parts of a tight oil reservoir.

In this paper, equations of state (EOS) calculations are conducted in order to see the effects of confinement on a CO2 injection process in tight oil reservoirs. On the basis of Cardium reservoir properties, numerical reservoir simulations are run to investigate the effects of confinement caused by a small pore throat size in 50 nm and 10nm on the CO2 injection process. Comparisons of CO2 near-miscible and miscible processes are made with various pore throat sizes. Results show that confinement effects in tight formations help to lower the bubble point pressure and boost an oil rate during CO2 injection. However, CO2 EOR efficiency goes down as formation pressure approaches MMP as mearsured in the lab. It is not necessary for CO2 injection to operate in an above MMP condition in tight formations, where a nanopore size is present. In this way, the volume of CO2 injected can be reduced. For tight oil reservoirs with a small pore throat size, a CO2 near-miscible process is more suitable than miscible flooding.
Prediction of Fracture Population and Stimulated Reservoir Volume in Shale Gas/Oil Reservoirs
Authors: Cheng Yuqing , Guo Boyun , Wei Na
Published: November 2015

Multi-stage hydraulic fracturing is a key technique used for improving well productivity in shale gas/oil reservoirs. However, the outcome of this technique is inconsistent from area to area. This is believed to be due to the rough design of hydraulic fracturing because of lack of knowledge of how fracture branches are initiated and populated. The objective of this study was to develop an analytical method to predict the population and the average length of fracture branches for maximizing Stimulated Reservoir Volume (SRV).

This study used calculus of variations to derive an analytical model for predicting the time-dependent population and dimension of fracture branches clusters of perforations. The rate of propagation of created fracture branches is simulated along the path of the minimum energy in the system. Lagrangian of the system is determined by the energy transfer from kinetic energy to pressure energy, elastic-potential energy, surface energy and heat loss due to friction. The condition for Hamilton's integral to be stationary is that the Lagrangian of the system satisfies the Euler equation.

The SRV was formulated as a function of dimension of fracture branches, number of perforation clusters and the orientation of the horizontal wellbore relative to the maximum horizontal stress. A case study of Woodford Shale indicates that the concept of FCI does reflect the complexity of fractures in the real world. The mathematical model reveals that after rapid growth at the very beginning, the number of fracture branches increases slowly. The growth rate of fracture branch declines with time. A sensitivity analysis with the analytical model indicates that the population of fracture branches at any given time increases with fluid injection rate. It is concluded that the growth rate of SRV in the reservoir declines with pumping time. The efficiency of creating SRV should be maximized by quickly pumping dense and viscous hydraulic fluid over a short time period in each stage of fracturing. The distance between perforation clusters should be optimized based on the average length of fracture branches given by the optimal stage-pumping time.

This study first time presents an analytical model to predict population and the average length of fracture branches. It provides petroleum engineers a rigorous method for maximizing the SRV in volume stimulation of shale gas/oil reservoirs.
Interventionless Unconventional Multistage Hybrid Completion: Fracturing Longer Laterals in Cemented Applications
Authors: Govorushkina A.. , Henderson C.. , Castro L.. , Allen R.. , Nasir E..
Published: November 2015

Operators have successfully drilled horizontal wells to make unconventional plays profitable. The next step is to drill extended-reach laterals to maximize the profitability of each well. Not only are longer laterals difficult to drill, they can be challenging to complete economically. The specific problem this paper discusses is the completion method of an extended lateral with a low bottomhole pressure. The standard completion method in unconventional plays requires post-fracturing intervention in the form of drillouts, using fracturing plugs or ball-actuated frac sleeves.

Coiled tubing-actuated fracturing sleeves offer a new completion method that eliminates the need for post-fracturing intervention. These sleeves have been used in the United States due to their ability to enable operators to obtain an unlimited number of single-entry targeted fractures while not adding ID restrictions or more post-fracturing intervention.

Large-bore fracturing plugs are also a new completion method that eliminates the need for post-fracturing intervention. These fracturing plugs enable operators to use their current plug-and-perforate method without the need to drill out before production is started. The plugs can also be deployed to great depths that coiled tubing cannot reach, making them extremely useful in extended-reach laterals.

This paper will review the hybrid stimulation method used to complete an extended-reach lateral of over 10,000 ft. with a challenging well geometry. The completion consisted of seven plug-and-perforate stages and 32 coiled tubing-actuated fracturing sleeves, providing an interventionless completion.
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

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

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

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

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

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

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

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

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 (>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

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.
A Comparative Study of Pore Size Distribution in Gas Shales
Authors: Zolfaghari Ashkan , Dehghanpour Hassan
Published: November 2015

Petrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we compare the PSD of shale samples using both of the adsorption and desorption isotherms of water (H2O), nitrogen (N2), and carbon dioxide (CO2).

The shale samples are collected from three wells completed in the Horn River Basin. A setup is designed to obtain the water sorption (adsorption and desorption) isotherms for shale samples. The model developed by Zolfaghari and Dehghanpour (2015) is used to calculate the PSD of shale samples from water sorption isotherms. BET (Brunauer-Emmett-Teller) analysis is used to obtain the N2 and CO2 sorption isotherms, and their corresponding PSDs. Also, SEM (Scanning Electron Microscope) images of the shale samples are utilized to visualize the pores of the shale samples.

The comparative analysis of PSDs indicates that different methods give different PSDs. All of the calculated PSDs indicate that majority of the pores are smaller than ~10 nm. The portion of pores less than than ~1.5 nm is larger when the PSDs are calculated using the water sorption isotherms compared to that of the BET analysis. The PSDs calculated from the water sorption isotherms also show pores of larger than ~40 nm, which is in agreement with the SEM images of the shale samples. However, BET does not detect these large pores.
Effect of Well Interference on Shale Gas Well SRV Interpretation
Authors: Pang Wei , Ehlig-Economides Christine A , Du Juan , He Ying , Zhang Tongyi
Published: November 2015

The stimulated reservoir volume (SRV) estimated from daily production rate and pressure is a vital parameter for appraising shale gas wells’ fracturing effect and production potential. However, when well interference occurs, the SRV estimation from rate-normalized pressure (RNP) analysis is compromised. This paper illustrates diagnosis of well interference and how it affects SRV calculation.

China is the third country to exploit the shale gas technology breakthrough after the United States and Canada. The Jiaoshiba shale gas play is the most successful shale gas reservoir in China with some wells’ cumulative production over 0.1 billion cubic meters in the first year. Production rate data has shown jumps in water production during hydraulic fracturing of neighboring wells. By combination of hydraulic fracturing process and production data, we detect the existence of well interference from the adjacent well, when well interference happens and the influence it imposed on the target well. We analyzed two pairs of target and neighboring shale gas well pairs using the RNP and its derivative. The log-log diagnostic plots for nearly all of the wells see unit slope, indicating boundary dominated flow within 1 year. Some wells see two unit slopes possibly indicating a change in the SRV after hydraulic fracturing in a neighboring well.

Well interference may be caused by interaction between primary hydraulic fractures and/or secondary natural fractures activated during hydraulic fracturing. Interwell interference has had a significant influence on the SRV interpretation.

Well interference has drawn people's attention in recent years, but its impact on SRV interpretation is rarely reported. This research may help to characterize shale gas's SRV and related parameters and to optimize well spacing.
Estimation of the Propped Volume Through the Geomechanical Modeling of Multiple Hydraulic Fractures Interacting with Natural Fractures
Authors: Raymond S.. , Aimene E. Y. , Ouenes A..
Published: November 2015

The application of a new Material Point Method (MPM) approach to model the proppant distribution in a reservoir where hydraulic fractures interact with natural fractures is presented and validated with an Eagle Ford well. The new MPM approach uses particles to represent the slurry and its effects on the hydraulic and natural fractures. The particles are injected in the hydraulic fractures and their action causes the hydraulic fractures to propagate and interact with the natural fractures thus providing new pathways for the proppant to move away from the wellbore when optimal natural fracture orientations are encountered. Elementary tests showed that long fractures oriented in 30 and 60 degree from the hydraulic fracture directions facilitate the proppant placement. However, the stress anisotropy seems to have little effects for fractures oriented in 30 and 60 degree but allows a better proppant placement for fracture oriented 90 degrees from the hydraulic fracture. The application of the new technology to an entire Eagle Ford well shows that the simulated proppant indicates a large propped volume towards the heel and a poor proppant placement at the toe stages as indicated by other methods. These field validated results, show that the macroscopic modeling of proppant distribution using the coupled solid/fluid MPM technology could be used in improving our understanding of the complex hydraulic fracturing process and the resulting proppant distribution that provide the needed initial stimulated permeability.