bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Spacing Optimization for Tight Sandstone Gas Reservoir
Authors: He Dongbo , Jia Ailin , Jia Chengye , Guo Jianlin , Ji Guang 
Published: July 2010

Abstract
In the past five years, tight sandstone gas reserves amounted to almost 50% of the newly proved natural gas reserves of PetroChina Co., Ltd. and will be one of the main targets of natural gas production for a long term.
Means to determine the reasonable well spacing are the key topics in the development of tight sandstone gas reservoir. Relationships among well spacing, gas recovery and ultimate accumulation production are involved. For tight sandstone reservoir, because of its lateral permeability heterogeneity, flowing barrier which decreases the effective drainage area for gas depletion is frequently detected. Wide well spacing would result in low efficiency for producing reserves and decrease the ultimate recovery factor. Small well spacing would probably cause pressure conductance between adjacent wells and decrease the ultimate cumulative recovery of individual gas well, which would decrease the economic returns seriously. Thus, ways to determine the optimized well spacing is a great challenge in the development of tight sandstone reservoir.
Based on experiences in development of Sulige Gas field, reasonable well spacing can be properly determined from the following three aspects under precondition of maximum economic returns and ultimate recovery factor. The first one is that 3D geological model was utilized in the well pattern optimization process. Data of outcrops, cores and production of local infilling wells were used in the modeling. Micro-facies and reservoirs were accurately evaluated by determination of the scale of gas bearing sand bodies and its distribution. The second aspect is that through dynamic analysis of gas well production, three parameters including effective drainage area, recoverable reserves and influence area were calculated. The third one is that reasonable well spacing was determined on basis of the compromised researches of correlations between average investment, accumulative production rate, influence area and ultimate recovery factor.
The Novel Model for the Invasion of Particles and the Filtrate of Drilling Fluids
Authors: Jianhua Wang , Jinsheng Sun , Jie Feng , Xin Tan , Bai Lijuan Michelle 
Published: July 2010

Abstract
For high permeability sandstone, the invasion of particles and the filtrate of drilling fluids is proven as one of the key factors accounting for reservoir damage. However, it is difficult to determine the invasion depth of particles and the filtrate of drilling fluids by using mathematical model. The novel invasion models of particles and the filtrate of drilling fluids are built up in dynamic condition by the mass conservation equation and radial friction loss equation, especially for the models taking into account the external and internal mud cake at the same time. Parameters of models are determined by experiments of API filter loss and dynamic filtrate loss. The simulating results indicate that the invasion depth of particles is deeper when the core permeability is higher. The invasion depth of the filtrate is influenced seriously by the different pressure, the viscosity of filtrate, the permeability and thickness of external and internal mud cake. Howerver, permeability and fluid viscosity of reservoir have little influence on the filtrate invasion depth.
The zwitterionic polymer drilling fluids are optimized. In an addition, ideal packing approach is applied to the drilling fluids. The instrument of dynamic fluid loss test is used to evaluate return permeability. The test results indicate that the ideal packing approach can reduce the dynamic filtrate loss. It also can improve the return permeability and reduce breakthrough pressure. The predicted results of this model indicate that the invasion depth of particles and filter is deeper without bridging agents. Ideal packing approach can reduce formation damage.
Integrated Static and Dynamic Study to Determine Optimal Infill Potential of a High Water-Cut Oilfield with Bottom Aquifer in Sudan
Authors: Limin Zhao , Yang Liu , Dezhi Bian , Xianghong Wu , wei Li , Xinzheng Zhang 
Published: July 2010

Abstract
Fluvial sands with discontinuous interbeds and highly variable permeability patterns pose a significant challenge for further development of high water-cut oil fields with bottom aquifer in Sudan. To obtain an optimal strategy for further infill drilling a multi-disciplinary study of reservoir characterization and performance prediction was undertaken.
Data from vertical observation wells and deviated wells, combined with seismic horizon data and inversion data were used to characterize the spatial distribution of reservoir architecture and interbeds. Petrophysical properties (porosity and permeability) models were then stochastically simulated under such reservoir frameworks.
To avoid the distorted or zig-zag grids, vertical stair-step faulting upscaling method was taken to ensure that cells were orthogonal. Fine grids where interbeds most often occured were kept during upscaling to serve as vertical fluid flow baffle. The accurate coarse model that provided a realistic understanding of the lateral variation and distribution of reservoirs in inter-well areas were then taken as the base to effectively develop reservoirs.
During history matching, some scenarios were tested as alternatives in pursuit of a history match. The history matching procedure revealed the significance of interbeds as vertical prevention of water coning and permeability streaks as conduits to effectively drain reserves. Performance predictions for infill well cases are carried out based on the remaining oil distribution. The infill wells are optimized based on the incremental oil rate which can improve the cumulative oil production and recovery factor.
Propellant-Assisted Perforating in Tight-Gas Reservoirs: Wireline Formation Tests Show Successful Stimulation
Authors: van Galen M. W. , Cuthill D. A , Peterson G. L. , Bouwmeester D. 
Published: July 2010

Abstract
Propellant-assisted perforating systems are used to stimulate the near wellbore region and to alleviate the formation compaction damage from the perforating event. This method involves combining a perforating gun with a high pressure, gas generating propellant. Detonation of the perforating gun causes the propellant to deflagrate. The resulting combustion gas enters the newly created perforations. This breaks down the compacted region and extends a fracture network from the perforation tunnels. Wireline formation testing has demonstrated the capability of this perforating method to stimulate beyond the depth of drilling and cementing invasion, especially in tight-gas reservoirs.
The wireline formation testing system is often referred to as a mini drillstem test (DST). It is conveyed into the well on wireline and it uses a dual packer assembly to isolate the perforated interval. With the pump-out capability of the tool, multiple drawdown and buildup cycles are performed. Pressure transient analysis (PTA) is applied to the measured pressure data to evaluate near-wellbore reservoir characteristics.
Depending on the formation parameters, there are two extreme responses observed in these tests: a radial composite model; or a linear fracture model. The radial composite model represents a higher permeability region in the near-wellbore area, surrounded by a lower permeability outer region representing the formation matrix. The typical radius for the inner region is up to 3 m. The linear fracture model represents a small fracture into the formation, generally with a fracture half-length of 1 to 2 m. In reality often a combination of the two models is more representative. All responses show less resistance to flow in the near-wellbore area, representing a positive cleanup and stimulation. Modeling indicates that the propellant-assisted perforation systems are capable of penetrating beyond any induced damage. This is often not the case when using conventional perforation charges.
This study comprehends 50 wireline formation tests in tight-gas reservoirs. These tests are used to demonstrate the successful application of propellant-assisted perforating techniques and to illustrate the different pressure responses created by propellant-assisted perforating in the near-wellbore area. The results are also compared to pre-job propellant stimulation modeling software analysis.
Risk of Losing Oil Reserve by Gas-Cap Gas Production in Malaysian Thin Oil Rim Reservoirs
Authors: Razak Ezzam A. , Chan Keng Seng , Darman Nasir 
Published: July 2010

Abstract
For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, the art of optimizing the oil recovery is to keep the oil rim in continuous contact with the producing wells in the oil rim. Therefore, the management of gas-oil contact and water-oil contact movement is extremely critical. To achieve the maximum results, force balance between aquifer drive, gas cap expansion, and viscous withdrawal (production) shall be carefully studied for a given reservoir at various stages of the production life cycle.
In this paper, the risk of losing oil rim oil to the gas cap when the force balance is impaired by weakening gas cap energy due to gas production is illustrated. This condition can also be observed due to impaired water injection or the improper placement of water injection wells.
For thin oil rim reservoirs with significant oil reserve, the strategy of hydrocarbon exploitation should be producing the oil rim oil first and then blowing down the gas-cap later to maximize hydrocarbon recovery (Ref. 1). For this reason, most of the produced gas shall be re-injected to the reservoir to keep the proper force balance and to enhance the improved oil recovery (IOR) options such as infill wells, water injection and enhanced oil recovery. Model simulation studies can demonstrate that the IOR benefit can severely reduced by producing gas-cap gas. A correlation between IOR recovery factor and gas cap gas withdrawal volume, for a particular thin oil rim reservoir in Malaysia, is shown and proposed.
Zhao Dong Drilling—A History of Innovation to Enable Continuous Improvement and Optimum Performance
Authors: Lin Low Siew , Mellor Andrew , Hill Robert , Scott Randy 
Published: July 2010

Abstract
This paper is a case study which pinpoints the key drivers that have created and sustained high performing organization using a mixture of local and international resources. It will show how a small, innovative, and empowered drilling team can consistently deliver top quartile drilling performance.
Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results
Authors: Hemphill Terry , Duran William , Abousleiman Younane , Nguyen Vinh , Tran Minh , Hoang Son 
Published: July 2010

AbstractIn today's increasingly complex well designs, often the range in drilling fluid densities required to prevent hole collapse without fracturing the wellbore, i.e. the safe drilling window, is narrow. This is often the case for wells having high angles of deviation, and is of particular concern in extended-reach drilling (ERD) wells. With increasing step-outs, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true vertical depth (TVD) remains fairly constant. The net result can be that as horizontal departure lengths continue to increase, the drilling ECD violates the safe drilling window.In a recent study presented to the industry, the effects of changes in the water phase salinity (WPS) of invert emulsion drilling fluids (IEF) were investigated as a function of rock shear failure for two very different shales: a deepwater West Africa shale and a more-competent Oklahoma shale. After a 3-hr exposure time, the changes in rock strength with different WPS levels were measured directly and results were qualitatively consistent for the two shales.In this paper, the effect of changes in the WPS of IEF on the safe drilling window is demonstrated in an ERD drilling scenario. The modeled failure envelope is first examined using conventional elastic modeling. Poroelastic modeling is then used to show the effect of changes in the safe drilling window resulting from changes in pore pressure. As a further step, changes in the safe drilling window are next shown using porochemoelastic wellbore stability modeling, where the effects of invert emulsion drilling fluid chemistry coupled with changes in pore pressure are introduced. The results show that the safe drilling window can be changed with invert emulsion chemistry, and that there is much to be learned using more advanced poroelastic and porochemoelastic modeling techniques.
Wiremesh: A Novel Shale Fracturing Simulator
Authors: Xu Wenyue , Thiercelin Marc , Ganguly Utpal , Weng Xiaowei , Gu Hongren , Onda Hitoshi , Sun Jianchun , Le Calvez Joel 
Published: July 2010

Abstract
A mathematical model was constructed to better characterize and predict the growth of induced hydraulic fracture networks (HFN) in naturally fractured formations such as shale. The model represents the HFN developed during a hydraulic fracturing stimulation treatment by a growing elliptic volume of the stimulated formation. It consists of two perpendicular sets of vertical planar fractures with mechanical interactions among themselves and with injected fluid fully accounted for. The model is further constrained by the amount of fluids pumped into the formation. Based on this mathematical model, a semi-analytical simulator was developed for design and planning of hydraulic fracturing stimulation jobs. It is capable of predicting the growth of HFN (height, length, width)predicting proppant placement (all directions or dominant fracture only) and fracture conductivitysupporting variable pump schedules for fluid and proppantsupporting limited entry for slurry injectionsupporting multiple fluid typessupporting multiple proppant typesdegenerating to bi-wing fracture
Comparison between Bit Optimization Using Artificial Neural Network and Other Methods Base on Log Analysis Applied in Shadegan Oil Field
Authors: Bataee Mahmood , Edalatkhah Saeed , Ashna Rahman 
Published: July 2010

Abstract
Bit selection is one of the main challenges in drilling operations. Since the effect of drilling bit in total cost is inevitable, bit selection is introduced as a vital task in planning and designing new wells. Using bits with proper code improve bit drillability otherwise false code leads in readily damage and wear the bit. Bit selection is based on the history performance of similar bits from offset wells and also is done by different methods based on offset well logs. There are many parameters intervening in drilling bit selection. Therefore, developing a logical relationship among them to assist in proper bit selection is necessary and complicated though. In such a case, Artificial Neural Networks (ANNs) is proven to be helpful in recognizing complex connection between variables. Well logs expose different parameters of the formation; one of the most important parameter is hardness of the formation which can help us choosing proper bit. So we can have a comparison between two methods and check the answers with history drilling data of field.
Cementing Solutions for Corrosive Well Environments
Authors: Brandl A. , Cutler J. , Seholm A. , Sansil M. , Braun G. 
Published: July 2010

Abstract
Main factors which are responsible for the corrosion of the cement sheath in wells are determined based on lab tests and field analyses from a literature survey. A description of the chemistry, mineralogy, physical properties of API well cements and their mechanisms of corrosion in the presence of aggressive formation and injection fluids (such as magnesia or sulfate containing brines and CO2) are given. API cement hydration mainly produces Calcium-Silicate-Hydrate (C-S-H) phases, which are responsible for the strength, and portlandite "Ca(OH)2" which is basically a weak point within the cement matrix. Increasing permeability and portlandite content reduce strength and chemical resistance of set cement towards corrosive media. The addition of pozzolanic materials eliminates portlandite and allows lowering the water content in the cement system. Both effects can reduce the permeability and improve the mechanical properties of set cement. Cement specimens were prepared and exposed to CO2 loaded water at 300 °F and 3,000 psi for 6 months. Mechanical properties tests, microscopy, and quantitative CaCO3 analyses revealed significantly less corrosion and negative impacts for an API cement-pozzolan blend compared to a conventional API cement design at same density. Practical and economical concepts for improvements of the cement sheath with respect to cement slurry design, cementing process and the impact of factors such as temperature or cement admixtures are presented to mitigate cement corrosion.
Integrated Fractured Reservoir Characterization and Connectivity Study in the Cantarell Field
Authors: Bustos Arturo Vazquez , Eduardo Aguirre Cerda , Febres Anurfo , Antonio Villavicencio Pino 
Published: July 2010

Abstract
This paper presents a multidisciplinary and integrated approach that can be used for understanding the connectivity and conductivity in fractured reservoirs. A case study from a carbonate reservoir in the Cantarell field in Mexico will be used to illustrate this approach. The fracture model is constructed by using seismic volumetric curvature attribute. The characterization of 3D fracture model is made with borehole images and fracture seismic classification analysis, which help to identify the two main scales and three sets of fractures in the reservoir. Fracture networks made by long size fracture corridors are assumed to be imposed on the small size diffuse fracture density fields. The 3D fracture model by integrating reservoir engineering data, including mud losses during drilling, flow meter data, transient well test analysis and water production data, resulted in the calibration of effective hydraulic conductivity for each fracture type. Based on the 3D fracture model, the hierarchical modeling concept is taken into account in effective permeability tensor computation. Matrix and fracture parameters including fracture density, length, aperture and orientation are calibrated and used to generate 3D fracture- permeability models for the reservoirs. An effective permeability model on a directional fracture-set base is developed to quantify the reservoir conductivity. In this paper, case studies are used to illustrate applications of these technologies and their efficiency in interpreting unexpected field production features such as early breakthroughs and better understanding the controls on the oil recovery.
Parallel Simulations of Commercial-Scale Polymer Floods
Authors: Yuan Changli , Delshad Mojdeh , Wheeler Mary F. 
Published: July 2010

Abstract
Despite advances in numerical techniques and computer hardware, numerical modeling of commercial scale mechanistic polymer floods remains a challenge. A low order finite difference scheme defined on coarse grids (standard practice in oil industry), tends to smear the front and mask the benefit of polymer solutions whereas the more accurate finer grids require excessive computer run times. A comprehensive polymer module has been added to our in-house reservoir simulator to benefit from parallel capability, efficient algorithms, and accurate grids to make fine grid field-scale polymer flood simulations possible.
Polymer flooding is a mature technology to economically recover additional oil from medium to heavy oil reservoirs. Polymers are added to the water to improve the sweep efficiency in heterogeneous formations by reducing the water mobility (ratio of effective permeability to viscosity). Polymer is transported in the water phase by convection, diffusion, and dispersion and delayed by the adsorption of polymer on rock surfaces. Polymer properties include adsorption, permeability reduction, rheology, and inaccessible pore volume. Polymer solutions often exhibit non-Newtonian rheological behavior where the viscosity decreases as the shear rate increases. However, large hydrolyzed polyacrylamide polymers (HPAM) with molecular weights on the order of 20 million or greater exhibit shear thickening behavior where above certain critical shear rate the viscosity increases.
This paper describes a reservoir simulator with a comprehensive polymer property model and parallel capability on a cluster of PCs. Simulations of commercial scale polymer floods are performed using fine grid and multiple processors. The impacts of elongational polymer viscosity and near wellbore flux calculations are evaluated.
Application of Lithofacies Models to Characterize Unconventional Shale Gas Reservoirs and Identify Optimal Completion Intervals
Authors: Mitra Arijit , Warrington D. , Sommer A. 
Published: July 2010

Abstract
Unconventional shale gas reservoirs are economically viable hydrocarbon prospects, and their development has rapidly increased in North America. These reservoirs must be routinely drilled horizontally and hydraulically fracture stimulated to maximize production rates. Identification of the different chemostratigraphic units or lithofacies that make up these reservoirs is crucial for devising completion strategies because some lithofacies are more favorable to gas recovery due to their organic content and geomechanical characteristics.
Lithofacies are indicative of eustatic changes during deposition and are typical geo-markers related to the preservation and amount of accumulated Total Organic Carbon (TOC) for a given basin. Gas content is related to TOC and varies according to lithofacies. Based on the mineralogical and TOC content, some lithofacies are favorable for gas production (e.g., siliceous lithofacies) and the geomechanical properties of these lithofacies often possess low fracture gradients that are conducive to forming extensive fracture fairways for recovery of gas. Other lithofacies can be fracture barriers and zones of fracture propagation attenuation (e.g., carbonate lithofacies).
A shale gas facies expert system was developed with the goal of chemostratigraphically characterizing different shale plays and utilizing an integrated petrophysical reservoir evaluation approach to identify optimal completion intervals. This system can aid operators design selective completion strategies, which can potentially reduce fracturing expenses and optimize well productivity. The expert system incorporates a combination of density, neutron, acoustic, nuclear magnetic resonance and geochemical logging measurements. This system first characterizes the lithofacies based on their geochemical makeup and then flags the most favorable and unfavorable zones using a simple "stop-light" approach based on the petrophysical and geomechanical properties.
This paper presents facies models for the Barnett Shale, the Haynesville Shale, the Marcellus Shale, and the Woodford Shale applied to a case study well in each of these plays.