bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture Network Development and Proppant Placement during Slickwater Fracturing Treatment of Barnett Shale Laterals
Authors: Xu Wenyue , Thiercelin Marc , Calvez Joel Le , Zhao Ruhao , Ganguly Utpal , Weng Xiaowei , Gu Hongren , Stokes Jerry , Moros Horacio
Published: February 2011

This paper presents an application of the wiremesh hydraulic fracturing model to analyze slickwater fracturing stimulation treatments of three Barnett Shale horizontal gas wells. For each treatment stage, the created hydraulic fracture network (HFN) was characterized on the basis of associated microseismic events distribution, treatment data, and geomechanical properties of involved formation layers. A systematic analysis of all stages, such as the potential effect of earlier treatment stages on a later one, the relationship between HFN properties such as the fracture surface area and treatment parameters, etc, was also presented. The information obtained was then applied to examine proppant placement in each of the HFNs. Potential ways of treatment improvement and optimization for future jobs are discussed based on these analyses.
Revolutionizing Offshore Production by InLine Separation Technology
Authors: Fantoft R. , Akdim R. , Mikkelsen R. , Abdalla T. , Westra R. , de Haas E.
Published: February 2011

The separation process is the heart of the offshore production system. Conventional technology requires massive equipment to allow for required separation of oil, gas, water and sand. Most separation equipment is based on gravity separation principles that require larger retention times and low fluid velocities. These separators have over several years been subject to further development by introduction of new separation principles. Advanced separator internals have been an important contributor in this respect.

During the last decade, Inline Separation Technology has successfully been introduced to several applications. Inline Separation is separation in pipe segments instead of within large vessels. Especially separation by use of cyclonic forces has been important. Inline technologies for separation of gas and liquid, oil and water as well as sand from liquid and multiphase streams have been developed and are already used extensively in retrofit applications to increase the performance and capacity of existing offshore production systems.

As the inline technology matures, total production systems can be developed based on use of inline separation technology. This will allow for substantially more compact and cost efficient field developments. It will also enable new applications, such as heavy oil and deepwater subsea applications, which are not feasible to develop with conventional technology.

This paper gives an overview of the inline separation technology and how this technology can be used to make improvements to offshore production system designs.
Landslide Hazard Assessment, Monitoring, and Stabilization: Villano Oil Pipeline System, Ecuador
Authors: Vasconez F. , Estrella M. , Velastegui A. , Nunez J. , Ponce H. , Riofrio P.
Published: February 2011

The Well sites of the "Villano" oil field are located on abundant biodiverse areas, part of the primary rain forest of the Upper Amazonas Basin. Due to its geological, geomorphological and climatic situation, the flowline that transports crude oil outside of this highly sensitive sector and the secondary pipeline that transports dehydrated oil to the Trans-Andean pipeline, are strongly susceptible to the affects of landslides, which can break the pipeline causing a serious environmental impact.

To assess the landslide hazards of the whole oil-pipeline route, the topographic basis maps were based on the aerial photographs utilizing aerial photogrammetric, restitution and rectification. Geological and landslide inventory maps were elaborated through photo-geology and fieldwork. For each identified landslide, the cinematic, intensity of the process and probability of occurrence was evaluated. These parameters were charted by degree of danger. All this information was integrated into a Geographic Information System (GIS). On the second phase, main active and potential landslide areas are being investigated in detail and are being monitored with inclinometers, stand piezometers, crackmeters and survey monitoring. They are numerically modeled and stabilized.

After more than ten years, since the operation began, there have been no pipeline ruptures. One of the case-examples is the landslide of kilometric point K-25 of the flowline, where a preventive action was taken to construct a variant of the oil-pipeline-route based on various analyses. It was also necessary to perform stabilization works on another unstable hillside within an ecological Reserve. A cable bridge was constructed to support a portion of the pipeline.

This methodology could be applied in other pipeline systems. Nevertheless, it is worth mentioning that timely identification of hillside instability is very important. For this reason, preventive maintenance of the right-of-way must be performed constantly.
Pore Scale Simulation of Flow in Porous Media Using Lattice-Boltzmann Computer Simulations
Authors: Boek Edo
Published: February 2011

We describe the ongoing development of lattice-Boltzmann (LB) computer simulation codes to study flow in porous media at the pore scale. LB simulations have evolved over the past decade and are now used as a tool to calculate both single- and multi-phase flow properties directly at the pore scale using X-ray Micro Tomography (XMT) pore space images. We will review the development of our codes to study flow in two-dimensional micro-models, viscous fingering, chemical reactions, hydrodynamic dispersion and non-Newtonian flow. In three dimensions, we have developed our codes to calculate the flow in XMT images of the pore space, for both single- and multi-phase flow, resulting in predictions of the permeability. Very recently, we have extended the multi-phase flow model to include surfactants for reduction of the interfacial tension and wettability alteration.
Shale Gas Production Decline Trend Comparison over Time and Basins
Authors: Baihly Jason , Altman Raphael , Malpani Raj , Luo Fang
Published: February 2011

Production from shale gas reservoirs has formed an increasingly large part of the U.S. natural gas mix in the last few years. More than half of the rigs in onshore U.S. will be drilling horizontal wells with a large majority in shale plays. (Baker Hughes, 2010) Within the last year, shale gas plays have dominated the onshore U.S. natural gas drilling activity, with this boom occurring during a time of economic uncertainty. However, skepticism has recently been placed on shale gas production decline trends from consultants and investment firms, where estimated ultimate recoveries (EURs) and the overall economic feasibility of shale gas plays have been brought into question.

EURs of shale gas wells have been forecast in a number of ways within the industry. Some entities have been calculating EURs based on initial production rates (IPs). Others are applying the decline trends established in one basin to a different, newer basin with less production history. In other cases, two different operators may use different trend types in wells that are in the same location.

This paper seeks to more accurately assess the decline trends and EURs of these shale plays, if the decline trends are improving, and what returns are required to make a well economically feasible. This study compares the production trends of horizontal wells in the Barnett Shale, Fayetteville Shale, Woodford Shale, Haynesville Shale, and Eagle Ford Shale plays, analyzing each over time to determine if there have been improvements in production. Where applicable we address the impact that technology has made in this enhanced production. Furthermore, the decline trends of horizontal shale to horizontal tight gas sandstone plays are examined to look for differences and shed some light on potential EURs.

The results of the analysis helped establish which decline trends could be used to determine the EUR of these horizontal shale wells, or if a better methodology may exist. A basic economic analysis to estimate breakeven gas price for a median (P50) horizontal well in each play was performed.
Accurate Simulation of Shale-Gas Reservoirs
Authors: Andrade Juan , Civan Faruk , Devegowda Deepak , Sigal Richard
Published: February 2011

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

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

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

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

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

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

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

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

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

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

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

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.
Using Mudlogging Data to Prevent Drilling Problem when Approaching Granite Basement of Cuulong Basin
Authors: Han Dinh , Nguyen Phung , Le Chung , Nguyen K.H. , Nguyen L.H. , Chu P.T.
Published: February 2011

The paper is the case study of catching basement in specific Basin of CuuLong which is considered as major production field of Vietnam. The case study is conducted on experience of Mud-logging service and Well Site Geologist (WSG) service of PVDLogging, which is subsidiary of PVD Company.

Production of the basin is mainly found in fractures of Granite basement. Those fractures could cause the major loss of drilling fluid when hitting the top of basement (TOB). The accuracy in identification of this top while drilling is one of the key successes of drilling operations.

Methodology is combination of drilling parameters behavior accordingly to the bit type when approaching the top of granite with or without confirmation of lag data and mud-logging data, such as formation gas, lithology and variation in mud pit volumes. The appropriate application of this method is able to catch the TOB in this field earlier than using Logging While Drilling (LWD) data which usually come later due to the nature design of Bottom Hole Assembly (BHA).
Openhole Stability and Solids Production Simulation of Emerging Gas Shales Using Anisotropic Thick Wall Cylinders
Authors: Hoang Son K. , Abousleiman Younane N.
Published: February 2011

Although unconventional gas shales have become accepted as the game changer for natural gas (International Energy Agency’s 2009 World Energy Outlook), laboratory as well as simulated data of openhole completion and production accounting for the inherent anisotropy and low permeability of gas shales are still extremely limited, due to the great challenges in testing and modeling of shale under in-situ openhole conditions. First, shale frequently exhibits substantial mechanical anisotropy that affects the stress distribution around an open hole. Second, the intrinsic low permeability of shale, sometimes on the order of nano-Darcies, magnifies the effects of time-dependent pore pressure on the effective stresses and could cause complex rock failure behavior. In this study, the response of anisotropic thick wall cylinder shale samples under realistic laboratory time-dependent loading, simulating near-wellbore or near-perforation production stresses, is modeled and analyzed taking into account fully coupled fluid and shale matrix interaction to address these challenging issues. Extensive experimental results including thick wall cylinder tests on an anisotropic low-permeability shale were analyzed using the developed analytical simulator. The analysis showed that depending on shale permeability and loading rate, solids production could result from either shear collapse mechanism or a combination of shear and tensile failure of the rock matrix. Thick wall cylinder tests on Woodford Shale and Barnett Shale were also simulated using experimentally measured mechanical and petrophysical properties. The results showed that the stress required to initiate solids production significantly depends on the loading rate as well as sample size, and is considerably higher than predicted by conventional elasticity theory. The presented modeling will be essential for designing and interpreting thick wall cylinder tests on gas shales as well as the ensuing modeling of gas production from these formations. The results on Woodford Shale and Barnett Shale will serve as guidelines for field operations and future laboratory testing.
CO2 Sequestration Wells - The Lifetime Integrity Challenge
Authors: Smith L , Billingham M A , Lee C-H , Milanovic D. , Lunt G.
Published: February 2011

The technical challenges of CO2 injection wells are highly dependent on the individual well design parameters, principally the formation being injected into (saline aquifer versus depleted gas formation) and the quality (impurity levels) found in the CO2 source gas. These factors will impact the potential corrosion and other material degradation challenges which may threaten the well components including injection tubing, injection casing, cement and packer materials. The long term integrity of these components is critical to the injection phase of the life and the suspension and abandonment phases (depending upon the strategy selected for well abandonment).

A key part of the acceptance of CO2 sequestration as a safe and reliable greenhouse gas control mechanism will be the proof that the well is truly leak-free. This integrity management element requires a comprehensive monitoring and pro-active warning system which highlights developing integrity issues before they become acute. Key well parameters requiring daily monitoring and intermittent testing have to be identified developed from industry international standards and regulations. Continuous well condition monitoring will require a dedicated well integrity software system which can integrate all relevant data from multiple sources. Data must be continuously automatically analysed using the software with developing well integrity problems identified and alerted to the operators before conditions become critical. Such a software has been recently deployed in gas storage wells and can be customized to CO2 sequestration wells.
Engineering a Successful Fracture-Stimulation Treatment in the Eagle Ford Shale
Authors: Stegent N. A. , Wagner A. L. , Mullen J. , Borstmayer R. E.
Published: February 2011

The Eagle Ford shale in south Texas is the one of the most recent developments in unconventional reservoir exploration. Numerous existing completion methods have been applied in this nano-darcy formation with various degrees of success. The horizontal Eagle Ford wells in the northeast area of the current Eagle Ford play (DeWitt County) require a completion strategy that is reservoir specific. The production in this area has a high liquid/gas ratio and presents different challenges for commercial development than those in the typical “high-rate water frac” completions associated with dry-gas shale stimulation theory. Previous high-rate water frac completions in this area typically associated with the “Barnett-style shale stimulation” achieved poor results. Core analysis shows that a low Young's Modulus (YM) (soft rock), high clay content, and the potential for high liquid-hydrocarbon production require the need for a different completion strategy. Swelling formation clays and proppant embedment were formation issues to consider along with the multiphase hydrocarbon production. Higher conductivity fractures would be required, but various unknowns existed: How many frac stages should be pumped?How much proppant should be pumped on each frac stage?What type of proppant should be used?What mesh proppant should be used?What perforation scheme was needed?What type of completion fluids should be used?What injection rate was needed?How would fracture-injection issues be handled?

This paper discusses how a collaborative, engineered approach was applied to the completion of the Eagle Ford shale to deliver a commercial asset. To address the unknowns, the methodology included geologic and reservoir understanding applied to the stimulation design and execution. The stimulation resulted in hydrocarbon production that exceeded expectations. Comparative well results will be discussed.
Technically and Economically Improved Cementing System with Sustainable Components
Authors: Brandl A. , Bray W.S. , Doherty D.R.
Published: February 2011

The benefits of cementing systems containing high percentages of pozzolanic materials (abbr. “pozzolan” systems) were investigated and compared to conventional API cement systems at same densities. Besides the presentation of technical results based on laboratory tests, economical and ecological features were also considered. For the tested pozzolan systems up to 65% of the cement was substituted with sustainable minerals, resulting in a significantly reduced CO2 footprint and costs. Slurry performances (rheology, stability, and fluid loss control) as well as properties of the set systems (water permeability, compressive and tensile strength) were evaluated for various densities and temperatures. The results reveal that the pozzolan systems generally require lower additive dosages to adjust the desired slurry performances. Furthermore, strength and durability (towards retrogression and corrosion) are consistently more favorable for the pozzolan systems. Findings were related to the working mechanisms of the used pozzolans in cement systems. The study proves that improved technical performance, economics, and sustainability can be combined together in appropriately designed pozzolan systems.
Application Mapping Methods in Well Intervention Planning
Authors: Volkov V. G. , Volkov M. G. , Elichev V. A. , Topolnikov A. S.
Published: February 2011

The paper proposes a system approach to well intervention planning based on application area mapping. A sorted set of graphs, schemes and maps reflecting underlying analytical models is used as the input material for a workflow-controlled express analysis of the technological decisions made that will help in forecasting future intervention operations.

The most problem is that we have a lot of different information. The main idea is to combine and filtering the information and build easy to analysis pictures using various visual representation techniques. So fast reservoir development analysis becomes possible and we can use it to support real-time and "quasi" real-time operations.

The graphical analysis workflow is subdivided into the following stages: importing the input data; processing the input data (applying the required criteria, templates and models); output of the resulting information; and generating the final conclusions. This method is considered efficient in intervention program designs, as long as it: allows of simultaneous processing of data obtained from different sources; is founded on time-proved models and algorithms; makes use of various visual representation techniques (trend lines, threshold levels, applicability boundaries, threshold efficiency and economic practicability); and dramatically reduces the analysis time.

Those methods have been successfully applied during the development planning of the oil fields in Russian West Siberia. It is planning to automate those methods and use those for Decision Support Centers.
Real Time Data Management and Information Transfer as an Effective Drilling Technique
Authors: Vogel Steve , Asker Jamal
Published: February 2011

Description

This paper is presented to enlighten operators and other drilling organizations in the cost-effectiveness and importance of real time data management techniques and information transfer complimenting technology in drilling operations at certain scenarios.

Applications

The techniques in this paper will increase the awareness of real time drilling efficiency and cut drilling cost. The techniques included are; continuous monitoring of real-time drilling parameters for quality and consistency, a seamless mechanism to correct inconsistencies in the data delivery, effective informational transfer and solutions delivery. Unique applications to analyze drilling with mechanical specific energy (MSE) in real-time and not just MSE, but an efficient MSE, which takes into consideration BHA specifications and theoretical down hole parameters, the use of reference channels, which is data that has been obtained from a previous offset well and training the rig crew in drilling awareness and the understanding of drilling mechanics.

Results, Observations and Conclusions

The results of this execution include quality real time data delivery, increased operational awareness, streamlined decision making, improve drilling efficiency and lower drilling costs. The observations reveal that a review of historic versus actual real time data delivery, field case study results and methodologies enacted demonstrate the effectiveness of the use of this implementation and the value to the user. The conclusions made are that quality data will allow a sufficient real time drilling monitoring system which provides effective improvements in the drilling operations results.

Significance of subject matter:

Demonstrating the importance of quality real time data for drilling optimization practices.

Present methodology and characteristics for system employed.

Provide vehicle for additional cost savings to the E&P industry.

Benefit Knowledge Transfer process by reducing inconsistencies.
Successful Testing of Toe-To-Heel Waterflooding in Medicine Hat Glauconitic C Reservoir
Authors: Turta A. , Singhal A. , Hawkins B. , Fisher D.
Published: February 2011

The Medicine Hat Glauconitic C reservoir contains medium heavy oil, and was put on production in 1985. In 1993, a waterflood pilot was initiated; in 1996, several horizontal wells were drilled as producers, and they resulted in a spectacular increase in oil production. In 2001 a conventional field-wide waterflood was implemented. The waterflood included seven Toe-To-Heel Waterflooding (TTHW) modules involving 10 injectors and 18 horizontal producers, out of a total of 52 injectors and 100 producers.

Five of these modules that utilized vertical wells as injectors performed well; oil rate increased 2 to 11 times, as increases in oil production continued for several years, or stabilized. During the same period, the performance of conventional waterflood modules was characterized by reductions in decline of oil production trends. Two TTHW modules that used horizontal injectors performed similar to conventional waterflood modules.

The best performance was shown by Module # 5 (involving two horizontal producers and two vertical injectors), located in the best quality reservoir. Compared to conventional waterflood pilot area nearby, the performance of Module #5 was superior, with oil production rates increasing 7-11-folds, while in the pilot area this was only 2-3 times; the water injected/oil produced ratio was 12–15 m3/m3 for Module #5, while it was 24–44 m3/m3 for the pilot area. The incremental oil recovery due to waterflooding from the TTH module # 5 was estimated at about 7%, and 5% from a nearby conventional waterflood area.

A statistical analysis for the whole field revealed that TTH horizontal wells produced at oil rates 30% higher than the non-TTH configuration horizontal producers.