bluuebunny/crossref_metadata_2025_split huggingface dataset:
Accurate Simulation of Shale-Gas Reservoirs
Authors: Andrade Juan , Civan Faruk , Devegowda Deepak , Sigal Richard 
Published: February 2011

Abstract
Current simulators make assumptions that may be inappropriate for modeling shale gas reservoirs. These assumptions are: 1) that the system exhibits instantaneous capillary equilibrium, 2) that transport can be completely defined by viscous flow (Darcy's law), and 3) that relative permeability is not flow rate dependant. To investigate these assumptions, a one-dimensional reservoir simulator was developed. This was then modified to implement a solution that does not force instantaneous capillary equilibrium and the effects of this phenomenon were studied.
In this paper, the requirements for a realistic shale gas simulator are first reviewed and results from a model study of a shale gas reservoir using a commercial simulator are briefly discussed. A simple example illustrates why instantaneous capillary equilibrium may be inappropriate and therefore justifies the need to develop simulators that do not make the above assumptions. The mathematical formulation used to implement a non-equilibrium capillarity model is developed and discussed.
Lastly, a set of simulation studies are discussed where saturation profiles for two-phase flow displacement are compared for capillary equilibrium and non-equilibrium conditions. We also investigate the effect of wettability by considering a 100% water-wet and a 100% oil-wet formation. The results indicate a dramatic impact on the saturation profiles produced by relaxing the capillary equilibrium requirement.
Optimized Cluster Directional Drilling Technology Achieves Great Success in the Low-Permeability Gas Fieldin Ordos Basin, West China
Authors: Cheng Rongchao , Wang Haige , Zhang Fucheng , Ge Yunhua , Chen Zhixue 
Published: February 2011

Abstract
Many strategies have been evaluated and applied by CNPC in the Sulige Gas Field that typically features in low permeability, low pressure, low quality and low productivity. Cluster well technique was supposed to be most appropriate to deal with the “four-low” reservoir related problems, especially in the vulnerable ecologic environment of desert area. The early pilot test, however, severely restricted its extension in larger scale due to the longer operation cycle and higher drilling cost compared to vertical wells. The Sulige development team was driven to re-design and optimize the cluster drilling project, with the principal objectives to further improve the rate of penetration and reduce the unit gas development cost. This paper will focus on the optimized cluster drilling concept that has been successfully applied in recent two years within Sulige, which is the largest gas field in China to date.
A “Cluster” usually consists of a reference “Mother” well and several “Daughter” wells from a single pad location. In Sulige, the “Daughters” are mostly directional ones and sometimes with auxiliary horizontal ones. Based on the optimized wellbore configuration, controlled trajectory and improved PDC bits, bottom hole assemblies and circulation fluids, a complete set of cluster well technique in a safe and faster drilling mode have been formed. Its application has resulted in an average ROP improvement of more than 36% and a dramatic increase of short- and long-term well economics, compared with previous cluster wells. The mature “Cluster” pattern triggers its complete extension in Sulige and promotes its trial applications in the Hailaer-Tamtsag Basin and Sichuan Basin.
This paper will present the optimized measures of cluster drilling and operational results within the Sulige field, and will discuss the cluster well design challenges, relevant drilling operations and subsequent post well evaluation. Recommendations on the helicoid hydraulic motor, directional wellbore profile and drilling fluid will also be presented.
Sand Jet Perforating and Annular Coiled Tubing Fracturing Provides Effective Horizontal Well Stimulation
Authors: Hill Eric , Zhao Zhi , Terry Adrian 
Published: February 2011

Abstract
Fracture stimulating horizontal wells is challenging using traditional workover methods. Running perforating guns in the horizontal well section, performing a fracture treatment, running a bridge plug, and then pulling or milling all the plugs has shown to be an extremely time consuming and expensive operation. An option using coiled tubing was proposed in China to improve on operational efficiencies.
Multiple zone completions using coiled tubing has traditionally used a straddle cup tool. This has proven effective for fracturing multiple zones in shallow environments. The drawback to this method is high pumping friction due to the small inside diameter of coiled tubing. With wells reaching ever greater depths and higher deviations, the multiple zone fracturing method using coiled tubing and straddle cup tools becomes unfeasible. A coiled tubing method using the larger area annulus was investigated and subsequently recommended for performing fracture treatments in deeper and/or horizontal wells.
The annular fracturing process involves first perforating by utilizing a coiled tubing sand jetting procedure and then pumping the fracture treatment through the coiled tubing by casing annulus. Following the fracture treatment, an ultra light weight proppant plug provides effective zonal isolation from the lower frac. The process is then repeated from the toe to the heel of the horizontal wellbore for the required number of fracture treatments. A sand cleanout at the end of the last fracture treatment removes sand isolation plugs. The method can quickly fracture stimulate a large number of sections in a horizontal wellbore with an easily removable isolation system.
Results to date have been improved well productivity and decreased workover time compared with traditional frac and plug methods in horizontal wells. A field wide case study is examined to discuss design criteria, job execution, improvements, procedures and results. As the world moves to deeper and more complex wellbore trajectories, this technique is a viable method for horizontal or deep well stimulation.
A Comprehensive Workflow for Early Analysis and Interpretation of Flowback Data From Wells in Tight Gas/Shale Reservoir Systems
Authors: Ilk D. , Currie S. M. , Symmons D. , Rushing J. A. , Broussard N. J. , Blasingame T. A. 
Published: February 2011

Abstract
Flowback data are defined as the early time-pressure-rate (TPR) data which are taken immediately following the completion and stimulation of a given well. Although typically discounted or even ignored, this data has a wealth of well/reservoir information. Analysis can provide forward-looking indications of long-term well deliverability as well as an early diagnosis of any potential production problems. Effective analysis of early TPR data, however, requires the utilization of all data sources and data types — for example: phase rates, pressures, choke settings, sand production, chlorides content, etc.
The purpose of this paper is to provide a comprehensive workflow for early-time flowback data which provides a unique visualization of these data, as well as a correlative and integrated analysis of these data (i.e., comparing different data types and functions, correlating one data type with another, etc.). The major steps in a generic "flowback" workflow include:
Collection and quality control of TPR and other well performance/completion data. Construction/calibration of a base well/reservoir model (including well completion and stimulation parameters). Construction/application of specialized plots to identify features in the data at a very basic level (i.e., water unloading). Correlation of flowback data using empirical and non-parametric models. Extrapolation of parametric and non-parametric models to provide predictive estimates of early-time well performance. Implementation of an assessment loop to guide future production/completion practices.
The proposed methodology is demonstrated using case studies of wells completed in tight/shale gas reservoir systems. Extensive discussion is provided for the analysis/interpretation of flowback data; as well as our efforts to identify and quantify factors which affect and control production. The approach used in this work is that of a "dashboard" of (static) diagnostic plots as well as correlations/plots for multiple-well sets of flowback data. While the focus of this workflow is the diagnostic analysis of flowback data, we also provide guidance towards the use of flowback and long-term well performance data in "model-based" analyses.
Experimental Investigation of Oil Recovery From Siliceous Shale by Miscible CO2 Injection
Authors: Vega B. , O'Brien W. J. , Kovscek A. R. 
Published: February 2011

Abstract
This work presents the results of tests using a low permeability (1.3 mD), medium porosity (34%) siliceous shale reservoir core sample initially saturated with oil followed by CO2 injection at miscible conditions. The tests had 3 primary flow conditions that replicate aspects of expected field conditions: (i) countercurrent exchange of carbon dioxide from fracture to matrix with consequent production of oil (ii) cocurrent exchange of carbon dioxide from fracture to matrix with oil production at the downstream core face, and (iii) a flushing stage where carbon dioxide is injected at a pressure drop of 25 to 50 psi to drive the core to residual saturation. The countercurrent and cocurrent conditions are conducted at very low pressure difference across the fracture at the face of the core and along the length of the core, respectively. The miscible injection of CO2 recovered virtually all of the original oil in place.
Results were simulated with a compositional reservoir simulator. The simulation model was constructed to be as similar as possible to the experimental conditions, including a heterogeneous permeability field. An exact match of the experimental results was difficult to obtain. Calculations agreed with the experiments on the total oil production but not the timing of recovery. Experimentally, more oil was recovered during countercurrent flow in comparison to simulation. Nevertheless, simulations did reveal CO2 penetration of the matrix via a countercurrent diffusion/dispersion mechanism. Incorporation of fracture-to-matrix CO2 transfer and matrix-to-fracture oil transfer were key elements of the simulation.
A Memory Cross Dipole Sonic Logging Tool and its Conveyance in Challenging Wells
Authors: Williams Peter , Elkington Peter , Mayor Terry , Eccles David , Long Dan 
Published: February 2011

Abstract
Sonic logs provide key data for seismic velocity models and have application in a broad range of drilling, completions and production challenges related to rock deformation. A new small diameter wireline-style sonic logging tool with memory capability reduces acquisition risk and extends the application of data into wells that are technically or commercially challenging for conventionally-sized tools (such as slim and/or high dogleg severity wells, and wells where logging out of drill pipe may be the only cost-effective evaluation option). Innovations in the design of the flexural wave transmitter, acoustic attenuator and receiver assemblies allow compressional and shear velocities and shear anisotropy to be determined from a uniquely small package that is not constrained by wireline data transmission rates (and can therefore be combined with the micro-resistivity imager and other high data density tools without compromising logging speed).
Performance is reviewed from operations around the world. Logs from shallow and deep reservoirs, including both conventional and unconventional reservoirs, demonstrate the robustness of the data over a broad range of common environments. The ability to accurately characterize slow formations (including from enlarged borehole intervals) is demonstrated, and minimum horizontal stress orientations inferred from the tool are shown to be consistent with independent analysis from image log data.
Modeling the Effect of Drill Pipe Rotation Speed on Wellbore Cleanout
Authors: Hemphill Terry , Ravi Krishna 
Published: February 2011

Abstract
The drilling industry has long had problems with debris left in the hole after completion of drilling and prior to a trip or to the running of a casing string or a production liner. Debris left in the hole can also lead to poor cement bonding with the formation. This problem can be especially bad in high angle or horizontal wellbores, where often large quantities of the debris can accumulate on the low side of the hole, thereby creating a lengthy interval potential cleaning problems.
Historically the industry has used centralizers and other tools to achieve a certain level of stand-off, whereby the axial flow of drilling fluid or completion fluids can flow past the debris and slowly remove the unwanted solids accumulation. The rotation of drill pipe to aid in wellbore cleanout has been used for many years, but the question of ‘how fast?” remains. In addition, many other ‘creative’ techniques have been tried in order to solve the problem, sometimes with some success and other times with little success. However, no model specific for wellbore cleanout in cases such as this exists.
In the last few years, the modeling of drill pipe rotation in drilling situations has advanced to the point where the helical flow characteristics of non-Newtonian drilling fluids can now be mapped in an annulus subject to axial and rotational flow. The axial and tangential velocities can be coupled to produce the annular point velocities for concentric and eccentric geometry. In this work, the velocity modeling is applied to predict wellbore cleanout efficiency for various particle sizes as functions of fluid shear stress in the annular flow stream and drillpipe rotation speed. Results will show rotational speeds required for the cleanout of small particles such as sand and for much larger-sized drilled cuttings.
New Aspects of Torque-and-Drag Modeling in Extended-Reach Wells
Authors: Mirhaj S. A. , Fazaelizadeh M. , Kaarstad E. , Aadnoy B. S. 
Published: February 2011

Abstract
The length and inclination of wells have increased significantly the past decades. The record horizontal departure today is about 11 km from the platform. Because of this evolution the number of offshore platforms to drain a field has been significantly reduced.
Excessive torque and drag can be critical limitations in extended-reach drilling (ERD). Torque and drag modeling is regarded as an invaluable process to assist in well planning and to predict and prevent drilling problems. It discusses how to use torque and drag calculations and measurements to plan long-reach well profiles, to execute drilling operations that minimize torque and drag effects, to monitor hole cleaning, and to plan jarring operations.
Torque and drag models have proven to be useful in all three stages of an extended reach well: planning, drilling and post-analysis. During planning phase the models are used to optimize the trajectory design to minimize the torque, drag and contact forces between drillstring and borehole wall. Used together with monitoring of hole conditions during drilling, T&D models are particularly useful in diagnosing hole cleaning problems, impending differential sticking, and severe doglegs as well as determining the possibility of reciprocating casing during cementing operations. In post-analysis the models help to determine true causes of hole problems that previously were unexplained or attributed to other factors such as mud weight, mud chemistry or problem shales.
In this study a general overview on most of the available literature on the subject is presented. Different models that have been developed for torque and drag predictions along with pros and cons of the models will be discussed and the validity will be checked by applying the model for one field case study from an ERD well in North Sea. The field case also demonstrates the challenges and importance of buoyancy effects and well path effects.
In situ Stress and Rock Strength in Rang Dong Field - Off shore Vietnam - Implications for Drilling in Basement Rocks
Authors: William L. , Sano Toru , Chai Ooi Kiam , Castillo David , Magee Marian , Burgdorff Katharine 
Published: February 2011

Abstract
An integrated geomechanical model which describes the rock strength, fluid pressures, and in situ stresses for the Rang Dong Field, offshore Vietnam has been developed using drilling data, geophysical log data, seismic data, and production/well testing data.
The field-wide state of stress was constrained by direct observation of drilling induced wellbore failure, including both breakout (BO) and drilling induced tensile fracture (DITF). Some of the fine-scale variation of the orientations of drilling induced failure relate to local influences of faults and/or fracture zones. These fine-scale features enable the understanding of how faults and fracturing in the basement are influencing the stress field.
Rang Dong Field is characterized by a strike-slip state of stress, where the intermediate principal stress is vertical (Sv=S2), and the maximum and minimum horizontal principal stresses (SHmax=S1 and Shmin=S3) are horizontal. SHmax is oriented approximately 152° N (NNW-SSE).
Development at Rang Dong Field has involved drilling of highly deviated, and in some cases horizontal, trajectories. These have been completed with some difficulty, depending on local conditions. In some cases nearly total fluid loss was experienced, and drilling was completed at depths as great as 4000 metres TVD with seawater and lubricant additives.
A China Basins Study for Suitability of Underbalanced Drilling Reservoir Evaluation
Authors: Yao Y. H. , Gangping Xie , Nas S. W. , Boutalbi S. , Du H. L 
Published: February 2011

Abstract
As the Underbalanced Drilling (UBD) technique develops, the benefits for eliminating formation damage and improving productivity have been well received by China National Oil Companies. Potential candidates for UBD reservoirs are tight sandstone, volcanic rock, as well as other low permeability hard rocks, but not all candidates are ultimately suitable. Experience in China suggests that inappropriate application of underbalanced reservoir drilling may have an adverse effect on protecting reservoirs, which in turn increases drilling risks. To achieve successful application of the technique, it is essential to first fully evaluate the suitability of the reservoir for underbalanced drilling. Furthermore, it has been observed that there is a lack of research when it comes to evaluate reservoir suitability with respect to UBD opportunities in China. Most current basin studies in China focus on geographic distributions and reservoir lithology characterizations rather than geomechanical properties.
This paper addresses these gaps by presenting the result of a China UBD basins study. We have applied our Reservoir Screening Tool software (RST) to reservoirs in 382 oil and gas fields and 17 onshore basins of China, to determine whether or not these reservoirs are practical for Underbalanced Drilling. Candidacy is determined by evaluating a number of formation damage mechanisms and related operational risks within the RST process. The research then results in the identifications of formation damage mechanisms of the UBD reservoir candidates, and also presents a rank from high potential to low potential reservoirs for the suitability of UB Drilling, and establishes the highest production potential applied by UBD technique.
Also, the objective of the research is to evaluate and rank the suitability of reservoirs for exploitation by UBD compared with conventional drilling and completion processes. Proper identification of UBD opportunities will minimize drilling risks for China national oil companies.
Development of the Gas Resource Assessment for the Papua New Guinea PNG LNG Project
Authors: Berryman A. J. , Braisted D. M. 
Published: February 2011

Abstract
In December 2009, Esso Highlands Limited, a subsidiary of Exxon Mobil Corporation, and its partners made the decision to sanction the PNG LNG Project to develop resources in the Southern Highlands and Western Province of the Papuan fold belt. This project will develop four gas fields and blow down the gas caps of four currently producing oil fields. Resource assessments in the project area are only poorly characterized by the integration of 2D seismic, surface geology, well data, synthetic aperture radar (SAR) and aeromagnetic data. Integration of dynamic data has been critical in the development of the resource assessment, with approximately 80% of total resource supported by production and pressure data.
The Hides Field with five reservoir penetrations is the key asset for the PNG LNG Project, supplying approximately 2/3 of the total project resource. Integrated structural mapping and comprehensive reservoir analysis in conjunction with pressure data sourced from existing wells defines the Hides volumes. Full field dynamic simulation models have been used to test the match to production history and determine the range of in-place and recoverable volumes. Comprehensive sensitivity analysis confirmed the validity of small amounts of production data to constrain the range volumes and demonstrated the resource robustness. A similar approach was applied at the Kutubu Main Block Toro (MBT) Field which has extensive well penetrations, production history and pressure data. Results of this work significantly narrowed the range of uncertainty in the Hides and Kutubu MBT resource and built confidence in the total resource base for the PNG LNG Project.
If at First You Don’t Succeed, Try, Try Again: Time Dependent Fracturing Success
Authors: Rylance M. 
Published: February 2011

Abstract
VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract; located onshore of the Mahakam delta, East Kalimantan, Indonesia. The PSC has produced over 70% of the originally estimated gas in place. The fields are relatively mature with most of the remaining gas resources locked up in the lower permeability reservoirs, where conventional tight-gas completion approaches have historically not been very effective in depleting the resources. A prize of 0.5 Tcf would be readily achievable, if these lower permeability resources could successfully be developed by an appropriate recovery method.
The lower permeability formations are typically sub millidarcy but achieving an economic production rate has been extremely problematic. Previous attempts at hydraulic fracturing within VICO, over a total of three decades, have been spectacularly ineffective and rarely enjoyed any production improvement at all. Geologically the reservoirs are distributary river channels, in a lower delta plain environment and therefore the size of some of these individual sands can be very limited. Alternative technologies, such as horizontal drilling are now being applied, but only within the larger sands which can easily support the necessary economics.
In late 2006 a very detailed review of the previous 30 Years of operations was performed, this review noted that there were five basic ‘skins’ which were causing problems for hydraulic fracturing. The ‘skins’ were: wellbore integrity, fracture QA/QC, formation relative-permeability, regional tectonics and poro-elasticity. The data was extremely convincing and a decision was made to implement a five well pilot in order to confirm the findings.
This paper will concentrate on describing the last two of these factors (i.e. regional tectonics and poro-elasticity); the paper will present the results of the study and the implementation phase of the pilot. Finally, the paper will round off with the forward plan for the Nilam G-Sands including the implementation of a three-year multi-well fracturing campaign based on the significant success and economics of the five well pilot programme and beyond.