bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Shale Reservoir Characterization: A North Africa Case
Authors: Chelini Valter , Muttoni Alda , Mele Maurizio , Rossi Elio , Galimberti Roberto , Ortenzi Andrea 
Published: February 2011

Abstract
In the last period with the rising price of oil and gas, the exploration and development of unconventional plays, that are already an economic reality in North America, are gaining more attention worldwide. It is common opinion that Gas Shale reservoirs are not peculiar only to the North America Basins. ENI E&P has focused attention on this type of unconventional reservoir, both in new countries and in the areas where it has historically been successful in conventional plays and where large amount of data are available.
New wells drilled in North Africa, planned to discover conventional hydrocarbon-bearing sandstone layers in the Silurian and Ordovician formations, have also been used to characterize in detail the Silurian Hot Shale that was normally interpreted as source rock. A dedicated data acquisition strategy was planned (logs and core) and, consequently, interpretation was carried out with the specific aim of characterizing this unconventional Gas Shale reservoir.
This paper documents the workflow used to characterize this unconventional reservoir.
It will examine in detail the wireline log interpretation based on integration with the experimental data from core. A robust characterization of a gas shale reservoir basically starts from core analysis (geochemical, petrographical, mineralogical and petrophysical) that are used for calibration and integrated in the wireline log interpretation. The benefits of these results will provide better evaluation of the hydrocarbon potential of Hot Shale in this area.
A Non Conventional EOR Technology Using RF/MW Heating Coupled with a New Patented Well/Reservoir Interface
Authors: Okassa Fabrice , Godi Antonella , Simoni Michela De , Matteo Manotti , Misenta Marco , Maddinelli Giuseppe 
Published: February 2011

Abstract
Production from heavy oil reservoirs has always been a challenge due mainly to one factor in particular high oil viscosity, implying low oil mobility within porous media. Different methods have been implemented over the years in order to reduce oil viscosity. Well-known methods include steam injection (e.g., Steam Drive, Steam Assisted Gravity-SAGD), CO2 injection, chemical injection etc. These types of application are mainly applied to onshore fields where space is available and operating costs are much lower with respect to offshore fields. Moreover they may not be feasible for shallow reservoirs where injection could be an issue due to uncertainties regarding the cap-rock sealing.
The scope of this paper is to present a patented nonconventional EOR method for heavy oil reservoirs using radio frequency/microwave heating. An adequate completion design and well-reservoir connection is used for heating the oil, thus solving the problems that impede RadioFrequency /MicroWave (RF/MW) penetration into the reservoir. Consequently, oil viscosity may be reduced, thus allowing its continuous production to surface (eventually by means of an artificial lift system included in the well completion). This method could be also suitable for offshore fields because it doesn't require high energy consumption, or large surface areas, or high operating costs. It can also be suitable for those shallow reservoirs not suitable for injection processes. This paper presents details of this new technology and associated simulation results showing its range of implementation.
Numerical Simulations of Screen Performance in Standalone Screen Applications for Sand Control
Authors: Mondal Somnath , Sharma Mukul M. , Chanpura Rajesh A. , Parlar Mehmet , Ayoub Joseph A. 
Published: February 2011

Abstract
The selection of optimum screens for standalone screen applications has historically been based on experimental data, rules of thumb and/or correlations. Recent sand retention tests conducted in various laboratories offer empirical screen selection criteria based on different sand size distribution parameters. Unfortunately, these experiments have their own limitations. They provide substantially different results based on how the tests are conducted and interpreted, leading to significant differences in the recommended screen type and screen opening size for any given sand sample. To resolve these inconsistencies and to better understand the physics of the problem, this paper presents three-dimensional numerical simulations to evaluate the performance of sand screens and ultimately to develop systematic screen selection criteria.
In this paper, we present results from three-dimensional, discrete element computer simulations of sand screens placed in contact with granular sand packs of ~100,000 particles. The numerical model computes the mass and the size distribution of the solids produced. The effect of the most important parameters, such as friction coefficient, fluid viscosity, pressure gradient and ratio of screen opening to sand size, on the mechanism of bridge formation and amount of sand produced are studied using both monodisperse and poly-disperse systems.
The results have helped resolve some key questions about the physics of sand bridge formation. Numerous simulations are conducted to replicate the experimental conditions over a wide range of screen opening to sand size ratios for wire-wrap screens. Good agreement is observed between the laboratory experiments and the simulations.
The simulation tool allows us to evaluate the performance of different screens without running expensive and sometimes inconclusive experiments, enhances our understanding of screen performance and helps to better design sand screens to meet performance criteria under a wide variety of conditions. In this paper, a new method is presented to estimate the mass and size distribution of the produced solids through wire-wrap screens. The method uses the entire particle size distribution of the formation sand and is validated with experimental and numerical data.
Casing Integrity Study for Heavy-Oil Production in Cold Lake
Authors: Hsu S.-Y. , Searles K. H. , Liang Y. , Wang L. , Dale B. A. , Grueschow E. R. , Spuskanyuk A. , Templeton E. L. , Smith R. J. , Lemoing D. R. 
Published: February 2011

Abstract
The Cold Lake heavy oil development is located in northeast Alberta, Canada. It began commercial operation in 1985 and uses a thermal recovery process called cyclic steam stimulation (CSS). During steaming cycles, the dilation and re-compaction that occur within the reservoir cause the overburden to deform much like the motion of flexing a thick telephone book. At weak overburden layers, shear slip plane(s) can form due to excessive shear stress overcoming the interlayer cohesion. Over multiple steaming/production cycles, the cyclic flexing and associated shear slip may lead to overburden casing fatigue failures.
In this paper, a multi-scale geomechanics modeling methodology is presented to predict the onset of failure due to CSS-related ultra low cyclic fatigue (ULCF). The modeling methodology consists of: (i) converting geological data into a representative finite element model of a single or multiple CSS pads, (ii) constructing a near-well submodel that includes thermal cement and casing, and (iii) constructing a detailed casing and connection submodel to predict the ULCF life of a pipe body or connection.
To predict the ULCF life of the casing and connection, an algorithm based on the concept of cyclic void growth is incorporated into the submodel. It provides the capability to predict the number of steam cycles to failure using the concepts of demand and capacity. This enables studying the effects of alternative steaming practices on overburden shear slip and casing/connection life.
Based on the learning from the multi-scale modeling, it is found that shear displacements on a shear slip plane can be superimposed using a single-well solution. By applying steaming and production scaling functions, the shear slip can be determined at any location and time. Integration of the single-well solution with ULCF algorithm has facilitated development of a new software tool that can be used to manage CSS operations in Cold Lake.
Deepwater Workover Experience With Extreme Hydrostatic Overbalance, 2002-2009
Authors: Myers G. , Cahill D. , Clay P. , Esquinance B. , Smith B. , Zeringue R. , Davis C. , Kenney T. 
Published: February 2011

Abstract
The paper presents planning and execution details for fluid loss control during workovers with extreme hydrostatic overbalance conditions, between 1,500 and 4,000 psi. Actual results for several wells from three deepwater fields in the Gulf of Mexico will be included. The information is applicable to operators that face similar requirements: 1) maintain well control throughout the workover, 2) mitigate any damage to the installed sand control or reservoir, and 3) complete removal of the fluid loss ‘barrier’ to re-establish production. The results will show that these workovers can be done effectively, with reliable sand control and high production rates maintained. Highlights and lowlights will be shared. Current choices of fluid loss pills, retrievable mechanical devices, and millable mechanical devices will be included; as well as a brief look forward. This paper establishes a knowledge base for extreme hydrostatic overbalance workovers in deepwater, which will increase in industry importance as more projects evolve to brownfield conditions.
New Real-Time Data Communication System Enhances Coiled-Tubing Operations
Authors: Taggart Michael , Murray Niall , Sturgeon Trevor , McNeil William 
Published: February 2011

Abstract
One of the most important parameters required while performing intervention operations with coiled tubing is determining the position of the BHA in the well. Surface depth measurement systems, however reliable, simply record the length of tubing conveyed into the well and do not precisely determine the position of the BHA. Previously, in operations where depth control was critical a logging cable was pre-installed in the coiled tubing string. In conjunction with logging tools this allowed realtime data to be transmitted to surface from the BHA. Unfortunately, with this cable installed, coiled tubing operations are negatively impacted in several ways: increased surface weights, limiting maximum depth achievable, increased circulation pressures, and perhaps most importantly introducing severe restrictions to the use of conventional ball operated downhole tools. The use of braided cable restricted the choice of fluids that could be reliably pumped through the coiled tubing string and introduced both slack management and costly maintenance tasks. For certain mechanical intervention operations the difficulties of maintaining electrical continuity increased.
A new system enabling real-time data to be transmitted from intelligent downhole tools to surface recording and display equipment has been developed. The primary purpose of this system is to enable depth critical operations to be completed with negligible impact on the conventional coiled tubing process and abilities. Coiled tubing weights and surface pump pressures are almost unaffected by the presence of this system and ball operated tools can be operated with confidence.
Trials using this new system have been completed. In addition to confirming the operational ability of the system, the data stream revealed previously unrecognised information. The benefit of this additional information will enhance the operational success of many coiled tubing operations.
This paper describes the complete system and discusses the findings and potential benefits confirmed during onshore testing and field trials. Operations involving the use of this system have been completed in the UK North Sea. The system performance and data collected during these operations are discussed.
Hands-On Teaching as Part of Petroleum Engineers Education: An International Experience
Authors: Teodoriu Catalin 
Published: February 2011

Abstract
This paper presents a new concept, named ad-hoc "hands-on teaching", in which the students are involved in developing experimental apparatus and designing experiments, a concept that has been successfully applied for both undergraduate and graduate levels. The experience gained during 3 years at Texas A&M University and 2 years at the TU Clausthal will be shown and analyzed, several experimental devices will be presented, together with their advantages and disadvantages. The project results have shown a more active student involvement into the class thematic, as well as a better and easier understanding of the phenomena. Student feedback was used as an important assessment parameter.
Understanding Diversion with a Novel Fiber-Laden Acid System for Matrix Acidizing of Carbonate Formations
Authors: Cohen C. E. , Tardy P. M. , Lesko Tim , Lecerf B. , Pavlova S. , Voropaev S. , Mchaweh A. 
Published: February 2011

Abstract
Recently, a new fiber-laden, self-diverting, and viscoelastic acid has been successfully used for matrix acidizing of highly heterogeneous carbonate formations The fibers have been designed to be inert under surface and pumping conditions, and their geometry allows them to form strong and stable fiber networks that can effectively bridge across natural fractures, wormholes, and perforation tunnels. Eventually, the fibers degrade into a water-soluble organic liquid that is produced back to the surface during flowback.
In the case of perforated wells, experiments suggest that diversion with fibers operates in three phases. First, as the early volumes of fiber-laden acid reach the perforations, the acid penetrates the reservoir as if no fibers were present. Second, as the fibers bridge, they accumulate inside the perforations and form a fiber cake. Third, the fibers plug the perforation, and the injectivity decreases locally, promoting diversion into other perforations. The pressure drop through a plugged perforation was analyzed by performing 340 separate fine-scale 3D simulations. The original work was based on theoretical and laboratory-based experiments, considering typical perforation schemes and for various permeability ratios between the generated fiber cake and the formation's original permeability. The results were compiled, and a correlation was made to model the resulting skin. The model was implemented into an acid placement simulator and was extensively tested and validated in the field.
In this paper, we present the model that describes the effect of fiber accumulation within perforations and explain how some of the model parameters such as formation-permeability contrast, fiber-cake permeability, and total permeability thickness (kh) may affect diversion efficiency. Case studies from field testing of the model illustrate methods of pressure history matching, job design, and treatment history evaluation.
A Comparison of High-Viscosity and High-Density Sweeps as Hole Cleaning Tools: Separating Fact From Fiction
Authors: Hemphill Terry 
Published: February 2011

Abstract
High-viscosity sweeps have long been used in the drilling industry as a tool to enhance hole cleaning. They have found application in vertical as well as high-angle / horizontal wellbores, with variable results. Sometimes they have been used in tandem pills or in two-part sweeps (e.g., a low-viscosity sweep followed by a high-viscosity sweep, a high-viscosity sweep followed by a high-density sweep, etc.).
Determination of the efficiency of sweeps centers on accurately predicting the settling velocity of various sized particles by using equations valid for turbulent and laminar slip. However, nearly all of the previous studies of particle settling velocity have been carried out under static flow conditions, which are rarely present while drilling a wellbore. Recent efforts in the modeling of the hydraulic effects of drill pipe rotation now allow more advanced modeling of the effects of drill pipe rotation on particle settling velocities under dynamic conditions.
These recent studies show that use of high-viscosity sweeps to improve hole cleaning is often not as efficient as use of high- density sweeps under the same conditions. This is especially true when larger-sized particles are resident in the wellbore, as when wellbore instability conditions persist. This paper presents data that shows the conditions under which viscous sweeps can be used and those conditions under which they should be supplanted by high-density sweeps for enhanced hole cleaning.
Diagnosis and Analysis of Nonlinear Transient Pressure From Permanent Down hole Gauges (PDG)
Authors: Zheng Shiyi 
Published: February 2011

Abstract
Long term transient pressure from a permanent down-hole gauge (PDG) is a combined response of the reservoir and many other sources. These include interference from other wells nearby, multi-phase flow and skin changing along with the production process, which generated a non-linear pressure signal, making well test analysis a challenging task for engineers.
If the transient pressure is non-linear, the traditional well testing principles, based on linear reservoir system, such as superposition and deconvolution are no longer valid for the analysis. In this case, engineer has three options in solving such well test problem: (1) Linearising the nonlinear problem, for example, using so called pseudo-pressure approach (2) Choosing a specially designed approach for this problem such as numerical well testing (3) Identifying or diagnosis for the cause given the nonlinearity of the reservoir response, then decompose the response to separate the linear and nonlinear components. Thereafter each of these can be analysed using the corresponding methods respectively.
This paper presents primary study results on the last option (3) mentioned above. Two cases causing the non-linear reservoir response were investigated. One is the changing skin problem. Another is the PDG pressure influenced by interference.
The study has demonstrated that before proceeding for any analysis, the diagnosis of the nonlinearity is essential to ensure the correct selection of the analysis method, particularly for handling long term transient data from a PDG. Examples include the changing skin case, if the resulting data are analysed using deconvolution algorithm with predefined constraints; the nonlinear response of the reservoir system can be smoothed out completely, leading to the wrong interpretation. While transient pressure combined with interference, deconvolution algorithm can't be applied at all.
This nonlinearity diagnostic key step should be included in well testing best practice of the industry.
Can Formation Relative Permeabilities Rule Out a Foam EOR Process?
Authors: Ashoori E. , Rossen W. R. 
Published: February 2011

Abstract
Foam is a promising means of increasing sweep in miscible and immiscible-gas enhanced oil recovery. SAG (surfactant alternating-gas) is a preferred method of injection. Numerous studies verify that the water relative-permeability function krw(Sw) is unaffected by foam. Studies of foam have used a variety of krw functions.
This paper shows a connection between the krw(Sw) function and SAG foam effectiveness that is independent of the details of how foam reduces gas mobility. For simplicity we analyze SAG processes in the absence of mobile oil; success without oil is a precondition to success with oil, and our analysis also applies to a miscible-gas process with oil in 1D in the absence of dispersion.
Fractional-flow methods have proved useful and accurate for modeling foam EOR processes. The success of SAG depends on total mobility at a point of tangency to the fractional-flow curve, which defines the shock front at the leading edge of the foam bank. One can determine total mobility directly from the coordinates of this point (Sw, fw) if the function krw(Sw) is known.
Geometric constraints limit the region in the fractional-flow diagram in which this point of tangency can occur. For a given krw(Sw) function, this limits the mobility reduction achievable for any possible SAG process. We examine the implications of this limitation for different krw functions.
These implications include the following: Increasing nonlinearity of the krw function is advantageous for SAG processes, regardless of how foam reduces gas mobility. SAG is inappropriate for naturally fractured reservoirs if straight-line relative permeabilities apply, even if extremely strong foam can be stabilized in fractures. It is important to measure krw(Sw) separately for any formation for which a SAG process is envisioned.
Improved Reservoir Management From Application of Intelligent Reservoir Completion Technology in an Extended-Reach Well in the Giant Al Shaheen Field, Offshore Qatar
Authors: Brink David , Ernst Sabine Dyrvig , Banerjee Sudeepto , Ekwue William , Ritchie Barry , Maurer Florian , Jensen Nels Michael , Jaafar M Rushdan 
Published: February 2011

Abstract
This paper describes a case study of planning, drilling, completing and production of an extended reach horizontal infill well in the giant Al Shaheen oil field, offshore Qatar. The completion has been designed with three surface controlled zones. The completion is supplemented by a straddle on mechanical open hole packers to isolate a section which has higher risk of pre-mature water breakthrough. This completion provides flexibility for selective production, production testing and performance monitoring.
Seven infill wells were planned in the Shuaiba formation for optimization of oil recovery. The first wells were brought online with higher than expected water cuts. A completion was designed for the fourth well in the area to improve reservoir management and liquid handling.
The well was successfully drilled with a long step out in order to avoid installing a cemented liner for well spacing purposes in the inner section. The completion was designed based on the downhole logs and record of mud losses while drilling and was installed to 15,000ft. The completion consists of surface controlled sliding sleeves and a ball valve complemented by a pressure gauge and chemical injection. The completion was installed inside a predrilled liner which separated the liner section into zones by timer set mechanical open hole packers. In addition a straddle was installed to isolate a natural fracture zone in the outer part of the well.
The completion was run and installed successfully and selective production testing has been conducted. The results show that the three zones have water cuts ranging from 5 to 50%. Selective control of the completion helps to optimise oil production and minimise water production as an integral part of an intelligent field management strategy. Net gain from this completion amounts to some 4,000 stb/day.
Sucker-Rod Pumping Failures Diagnostic System
Authors: Moisés G. V. , Andrade S. F. , Garcia A. C. 
Published: February 2011

Abstract
A decision support system was developed based on Failure Root Cause Analysis aiming to reduce the mean time between failures (MTBF) of sucker rod pumping wells. It collects, organizes and integrates data about pulling services, failures, and technical observations and uses a combination of Failures Modes and Effects (FMEA) and Fault tree (FTA) analysis techniques to generate diagnosis. The system is based on an ontology that describes the domain, including: equipments, failures modes and causes. The diagnosis is inferred by a specialist system based on production rules and identifies well severity level based on data aggregation algorithms, in particular, k-means, which clusters the behavior of similar wells given the subsurface reservoir and equipment characteristics, type of material installed and the failures characteristics. The sucker rod pumping failures diagnostic system is currently being implemented at Petrobras. Initial results are promising: even during pilot tests, analysts were able to detect problems with manufactures and a lack of synchronicity between component changes.