bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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

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

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

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.
Deep Diagnostics via Differential Microgravity Logging
Authors: Mever Thomas
Published: February 2011

Monitoring fluid movements and associated saturation changes over time is a key feedback element for enabling optimized reservoir management. Reservoir-wide inquiries made by time-lapse seismic acquisitions, though possible, are rare even in the world's biggest fields, and generally do not provide sufficient resolution or repeatability, nor a direct assessment of saturation changes. Conversely, conventional logging methods that do have high resolution and may provide the desired precision in saturation (e.g., pulse neutron logging and through casing resistivity methods), but do so on a localized basis, suffering from very limited depths of investigation. Thus, there exists a data gap, or opportunity, for geophysical techniques exhibiting moderate to large depths of investigation, with moderate or better resolution.

Time-lapsed gravity logging is one such method that if, given a significant "technology overhaul," could eventually close this gap. Subsurface measurements (versus those collected using various surface meters) benefit from enhanced signal-to-noise ratios by virtue of their immediate proximity to saturation contrasts and changes over time. Both practical results and analytic studies reported in literature establish gravity's intrinsic large depth of investigation. Furthermore, data relate directly and easily through bulk density to changes in fluid saturations.

The notion of reservoir monitoring via gravity logging is not new; however, measurement concepts and technology applied in emerging sensor development programs are. This brief synopsis gives insight to pursuits down one technology path – the BHg slim logging tool overviewed here aims to provide an order of magnitude improved performance compared to its precursor borehole gravity meter (BHGM), free of restrictions on well deviation and without a need to pull tubing.

The translation of gravity-centric tool performance (i.e., micro-Gal units) to g/cm3 density contrasts and component saturations requires specific problem geometry and reservoir properties, but is invaluable for providing a tangible illustration of tool capabilities to non-gravity practitioners.
Managing Geomechanics Principles for Proper Handling of Wellbore-Stability Problems in Shale and Depletion Effects on Formations While Drilling
Authors: Meng Fanhong (Frank) , Fuh Giin-Fa , Spencer Jeffrey A.
Published: February 2011

This paper describes two types of hole problems and wellbore stability solutions for drilling operations in North Sea fields: (1) severe shale cavings and wellbore collapse; (2) drilling through cap rock and reservoir formations impacted by large pressure depletion and reservoir compaction effects.

Field cases of wellbore collapses and failures in shale formations during high-angle drilling are presented along with a systematic program of comprehensive geomechanics investigation and evaluation necessary to prevent such events. The program includes analyzing drilling and log data analysis for rock strength and earth stress model construction, laboratory triaxial stress-strain tests on well core samples considering bedding plane inclination effects, 3D analytical modeling and 3D elastic-plastic numerical modeling analysis for determining optimum mud-weight (MW) windows for secure and stable well drilling.

Continuous well production can also present problems for in-field drilling as the severe pressure depletion and reservoir compaction will cause significant reduction in stresses and formation fracture gradient. These effects may occur not only in the reservoir, but may also extend significantly upward into the cap rock formations depending on the reservoir/formation stiffness contrast, reservoir size, thickness and depth, etc. Therefore, the optimum MW must be examined and recalculated based on the insitu stresses that can be altered by this effect. In summary, this paper will include the following: Analysis of actual drilling cases of severe shale caving and wellbore collapses/failures;Laboratory triaxial stress-strain tests on well cores considering bedding plane effects;Effective drilling guidelines based on modeling analysis of troublesome shale formations;Coping with reduced stresses and formation fracture gradient due to reservoir depletion and compaction effects;Use of wellbore strengthening material for drilling (and possible reduction in number of casing strings);Case histories of severe wellbore instability and lessons learned.
Application of Multizone Expandable Sand Screen Completions in Deepwater West Africa: Cased-Hole Functionality With Openhole Performance
Authors: Nicol Mark , Geddes Martin
Published: February 2011

Expandable Sand Screens (ESS) have been commercially available and applied in excess of 600 wells since 1999. ESS systems have performed well in a variety of application types, reservoir conditions and sand control environments. ESS systems were identified at an early stage of their development and implementation to have specific benefits and potential in order to complete multizone reservoirs in openhole in addition to the original goal of providing a viable alternative to openhole gravel packing. Such a multizone system has been developed and applied in various projects globally.

One such application where the ESS in a multizone reservoir that has achieved initial client objectives has led to subsequent further adoption and completion flexibility as result of performance. Initially specified as the preferred sand face completion for water injectors, the implementation of ESS in a West Africa deepwater field development has evolved significantly over 24 months.

The world's first 7.0" Multi-Zone ESS completion deployed and expanded from a floating vessel in deepwater, the project, in addition to setting some of the very early design goals, functional specifications and qualification requirements, has also driven some of the evolution of this openhole multizone sand face completion system. Performance of the ESS completion in water injectors from equipment supply, system installation, operational efficiency and subsequent injectivity drove the client completion team to open the application envelope by also applying the technology into producer wells. The producer wells have also yielded equally favourable performance results - operational efficiency, low NPT and excellent productivity.

The paper will detail the early design goals, functional specifications and qualification testing to allow system use as the base-case water injector completion, the evolution of the ESS system and adoption through the development of the deepwater project, describing lessons learned and overall performance of the ESS system in both water injector and producer application types.
Rate Allocation: Combining Transient Well Flow Modeling and Data Assimilation
Authors: Lorentzen Rolf J. , Saevareid Ove , Naevdal Geir
Published: February 2011

This paper presents an approach for rate allocation for individual wells by combining a transient well flow model and the ensemble Kalman filter. Specifically, we aim to utilize available high frequency measurements of pressure and temperature, focussing particularly on the early time period after changing influx conditions. The transition between two steady state flow periods implies natural excitation of the well flow, and during this phase an individual sensor experiences a golden age compared to the single value associated with a steady state. Thus, by taking proper advantage of the transient periods, it is reasonable to believe that important insight into the subsequent steady state conditions can be obtained.

We explore a couple case studies, indicating the feasibility of our approach and then draw some preliminary conclusions from our investigations.
Field Case Study on Formation Fines Control With Nanoparticles in Offshore Wells
Authors: Huang Tianping 'Tim' , Evans Brian A. , Crews James B. , Belcher Christopher K.
Published: February 2011

Various technologies have been developed in the industry to find efficient and cost-effective ways to control fines migration in producing wells. Migrating fines are often the source of formation near-wellbore due to their ability to choke a well's productivity by collecting in pore throats near the wellbore where flow velocity is high due to radial flow regime into the wellbore. It is important to minimize or prevent formation damage in the radial flow region around the wellbore to allow the well to operate at desired rate and bottomhole pressure. The typical recourse for formation damage resulting from migrating fines is expensive remedial stimulation treatments involving mud acid or hydraulic fracturing, which increases the well's operating cost.

This paper provides a field case study of using nanoparticles to treat proppant used on an offshore frac pack. The nanoparticles have significantly high surface forces, including van der Waals forces and electrostatic forces, to attach themselves to the surface of commonly used proppant. The nanoparticles that adhere to the proppant will adsorb migrating formation fines onto the proppant surface as the fines flow into the fracture. This will maintain well productivity much longer than untreated proppant in the fracture by preventing the fines from accumulating in the near-wellbore area. After the nanoparticle-coated proppant is saturated with formation fines, it can easily be cleaned up with conventional fluids and retreated with nanoparticles for continued capturing of formation fines.

The case history studies an offshore well that historically suffered systematic production loss due to migrating fines. The well was sidetracked and the new completion used nanoparticle treated proppant in the frac pack completion. After the treatment, the well's productivity was recovered and has maintained the recovered productivity for ten months without a formation fines issue.
Quantifying the Impact of Permeability Heterogeneity on Secondary Recovery Performance
Authors: Rashid B. , Bal A. , Williams G. , Muggeridge A. H.
Published: February 2011

A new and improved heterogeneity index is introduced that uses the shear-strain rate of the single phase velocity field to characterise heterogeneity in terms of its impact on performance. This index's ability to rank heterogeneous reservoir models is compared with that of the Dykstra-Parsons coefficient and the dynamic Lorenz coefficient. The new index is able to rank reservoirs, both accurately and quickly, based on performance for both miscible and immiscible fluids at a range of different mobility ratios. In contrast both the Dykstra-Parsons coefficient and the dynamic Lorenz coefficient are found to lack the sensitivity needed to be able to estimate the time to breakthrough of the displacing fluid and the recovery of oil at one pore volume injected.
High Performance Aqueous Insulating Packer Fluid Improved Flow Assurance and Reduced Annular Pressure Buildup in Ultra Deepwater Wells
Authors: Ezell R.G.. G. , Fontenot S.. , Robinson E.. , Cunningham L.. , Patrickis A..
Published: February 2011

Deepwater production well design and equipment installation present multiple challenges. One major problem is the uncontrolled heat transfer to outer annuli which can be detrimental to the integrity of the well. Annular pressure buildup (APB) could result in casing failure and heat loss from the production tubing causes dramatic loss of well productivity due to the deposition of paraffin and asphaltenes and could contribute to the formation of gas hydrates.

Vacuum insulated tubing (VIT) was initially utilized in the deepwater well completions to help alleviate well failure caused by APB. The operator requested an alternative to VIT that would provide the following benefits:

Reduced costs Minimization of APB or similar to VIT Increased flow assurance Ability to apply the downhole tools required to be installed in the production string

Ease of placement was also an issue. Typically VIT takes special handling equipment, long lead times, and adds 10-12 hours of rig time for running of the production tubing.

Customized high performance aqueous-based insulating packer fluid (IPF) proved to be a reliable alternative to VIT. A properly designed fluid having a density of 10.0 lb/gal and thermal conductivity (k) of 0.176 BTU/h ft°F was carefully prepared. The unique thermal-gelling characteristics of this state of the art fluid allowed for easy, rapid placement of the fluid in the well annulus. Once in the wellbore, the fluid has provided increased flow assurance as well as a reduction in APB thus resulting in increased well flow rates and improved profitability. Repeated field applications of this tailored aqueous IPF helped in achieving an overall cost reduction of more than 64% compared to utilizing conventional VIT. This paper presents detailed fluid formulations with laboratory data generated by specialized equipment, and discusses the fluid design criteria along with the reported data and economics.
Smart Well Re-Entry and Intervention in Offshore Angola
Authors: McNerlin B. , Shirmboh D. , Spearman J. , Price-Smith C.
Published: February 2011

The Greater Plutonio development in deepwater offshore Angola is BP's largest and highest producing subsea development in a sand prone reservoir. The development depletion plan stipulates 100% voidage replacement in multi-layered reservoirs; however, in a subsea environment drilling individual injectors into every produced zone is prohibitively expensive, so water injectors in multiple zones are completed as Down Hole Flow Control (DHFC) designs using wire wrapped screens across the reservoir sections. In June of 2009, problems were encountered during completion installation of the sixth DHFC water injector. Although the assembly was eventually deployed to depth and installed as planned, the problems encountered resulted in no injection into either the upper or lower zones. Coiled tubing intervention work was attempted to initiate injection, but further problems and rig time constraints led to the temporary suspension of completion operations. During the following months, a right scoping exercise was carried out on well recovery options, including recovering the existing equipment and recompleting if possible. Three months later the rig re-entered the well, whereby the coiled tubing intervention successfully cleaned the lower completion screen section exposing the lower zone, allowing rig based water injection to be successfully conducted. The lessons learned were incorporated into subsequent DHFC injectors, the next of which was completed in a project Best in Class time.

This paper discusses the general design of DHFC wells in Greater Plutonio, the difficulties encountered while deploying equipment into the sixth DHFC well of the project, the temporary suspension and recovery planning process, and the successful re-entry and coiled tubing intervention.
3D In-Situ Fluid Distribution Imaging at the Pore Scale as a New Tool for Multiphase Flow Studies
Authors: Youssef S. , Bauer D. , Bekri S. , Rosenberg E. , Vizika O.
Published: February 2011

In this paper we present a new experimental setup combining laboratory high resolution computed micro-tomography (MCT) with a flow microcell specially designed to reproduce in-situ multiphase flow experiments and monitor the fluid distribution at the pore scale. The objective is to describe the fluid saturations and distribution at different steps of the capillary pressure cycle (drainage and imbibition) while maintaining the sample under pressure in the cell to avoid fluid re-distribution. Experiments have been performed on a monomodal sandstone where the total porosity is resolved by the MCT. We compared successfully the saturation profiles calculated from the mean grey level of the 2D cross sections and the saturation profiles calculated by 3-phase image segmentation. The two above mentioned methods can be combined in bimodal pore systems to evaluate the fluid saturations in both micro (unresolved) and macro (resolved) porosity. Finally, we describe the distribution of each fluid at the different steps of the drainage-imbibition cycle and the influence of the pore geometry and interfacial tension on the oil trapping.
Stimulation With Innovative Fluid-Placement Methodology and World First Production Logging With Fiber Optic Enabled Coiled Tubing (CT)
Authors: AlDhufairi Mubarak , AlOmairen Khalid , AlGhamdi Saleh , Noya Vidal , Jacobsen Jan , AlSarakbi Samer , Ghani Adnan , Azrak Abdul Wahab
Published: February 2011

The coiled tubing (CT) e-line system is ideal to perform real time production logging (PL) in long horizontal wells, however, the wireline cable inside the CT can restrict the pump rate while the large volumes of acid normally pumped could potentially damage the CT pipe's integrity. Furthermore, using two different CT strings, one for pumping acid and another for performing the PL in real time is neither practical nor economical. A common current approach is to use a memory PL tool (PLT), with the associated drawback of missing/poor data quality and possible eventual misruns.

To overcome these challenges, a new CT multipurpose system has been developed, allowing real time PL and conventional applications. Leveraging on the telemetry offered by the fiber optic enabled CT (FOECT), already used for downhole measurements while treating in the M field; the new downhole assembly enables the use of standard PLTs in real time mode. At the surface, the converted optical signal is transmitted wirelessly to the PL engineer's portable computer; eliminating the need for conventional acquisition equipment and personnel.

In a world first application, the system was used in a land water injection well, after the stimulation job; obtaining the injection profile log with the same quality measurements as a conventional wireline conveyed log. Moreover, the data demonstrated a uniform injection profile.

The new multipurpose FOECT reduces the mobilization and logistics otherwise required, as well as the time and cost compared to existing alternatives. This new capability can be extended to other scenarios like offshore or remote environments, where operational costs have a larger impact. Ultimately, the system opens the door for performing diagnosis, treatment and evaluation in a single well intervention; making CT operations more efficient and providing more data for production engineers.
Well Completion Optimization in a North Dakota Bakken Oilfield
Authors: Zander Dennis , Czehura Michael , Snyder Daniel J. , Seale Rocky
Published: February 2011

First discovered in 1951, development of the Bakken formation in the Williston Basin has been problematic and inconsistent. However, technological advancements in horizontal drilling and completions in the past decade have steadily improved production results and consistency on a well by well basis. So much so, that the United States Geologic Survey (USGS) reported in 2008 that the undiscovered, technically recoverable oil in the Bakken was between 3 to 4.3 billion barrels.

How many fracture stages to run and how far apart to space stages in horizontal wells are prevalent questions asked by the oil and gas industry. This study provides insight into the advantages of various stage numbers and optimum stage spacing by analyzing up to 15 months of production results from horizontal wells targeting the Bakken in the Stanley Field, North Dakota. These wells were completed with open hole, multi-stage fracturing systems (OHMS) and production is compared to offset wells and field averages.

Advancements in OHMS completion and fracturing technology have enabled maximized production from this asset. The lessons learned and methodology can be utilized for other unconventional oil and gas plays around the world.
Viscous Oil Recovery Using Solids-Stabilized Emulsions
Authors: Kaminsky R. D. , Wattenbarger R. C. , Lederhos J. P. , Leonardi S. A.
Published: February 2011

An overview is given of the development and field testing of a non-thermal, viscous oil recovery technology that injects into a reservoir oil-external solids-stabilized emulsions (SSE) as a displacement fluid. The emulsion is generated on site using produced crude oil and water. Small amounts of added mineral fines are used to enhance the performance of naturally present surface-active components in the oil. Gas is dissolved into the oil to adjust the viscosity of the injected emulsion to be similar to that of the in situ oil. SSE fluid displaces viscous oil in a miscible-like manner with favorable mobility, which leads to to improved displacement and recovery. SSE is generally applicable to reservoirs with in situ oil viscosities of up to approximately 3000 cP and permeabilities on the order of one Darcy or more.

A series of laboratory tests were conducted to confirm the effectiveness of solids-stabilized emulsions as displacing agents. Specialized coreflood were used to measure emulsion stability, confirm process understanding, and to determine displacement efficiencies. After lab testing and reservoir modeling, a field pilot of the SSE process was designed, constructed, and operated. The field piloting confirmed the ability to generate and sustain injection of a solids-stabilized emulsion in the field and to propagate stabilized emulsions in the reservoir.
Innovative Well-Intervention Solutions Using Spoolable Connector
Authors: Howard Robert , Hriscu Joseph , Ehtesham Asif
Published: February 2011

Well intervention has seen significant growth in recent years because of increases in both new completions and workover operations on older wells. This has lead to development of larger and higher-grade coiled tubing (CT) for deeper and more challenging wells. The equipment, on the other hand, still needs to catch-up with the demands of bigger and heavier coil. Offshore installations present a challenge with weather and crane limitations. Onshore, road and bridge conditions often hamper shipment of large spools of CT. These issues lead to breaking the spool into two or three manageable sections and joining them on location. The increased cost, time, and equipment required to make a field butt weld make a mechanical connection the only acceptable alternative.

This paper presents the five-year development, testing, and deployment history of a mechanical, spoolable connector (SC) that has provided innovative solutions to one of the most challenging well-intervention problems (i.e., weight management of the CT string). SCs in sizes ranging from 1.5- to 2.875-in. OD were designed, built, and tested. A highly accurate finite element analysis (FEA) model was used to virtually test the design, resulting in industry-leading fatigue life. Correlation of FEA results with full-scale fatigue tests on 1.75- and 2.375-in. OD SCs, along with a case history of a 1.5-in. OD string, will be discussed.

A tapered OD (TOD) string with a SC enables two different outer diameters to be joined together on location, resulting in 30 to 80% weight reduction during transportation, compared to conventional strings. Combining it further with tapered wall thickness opens up new possibilities for deeper and more challenging deployments with depths exceeding 35,000 ft. Details on design and virtual testing of these strings is also shared.
The Effect of Live Crude on Alkaline-Surfactant-Polymer Formulations; Implications for Final Formulation Design
Authors: Southwick Jeffrey G. , Svec Yi , Chilek Greg , Shahin Gordon T.
Published: February 2011

Phase behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension with a specific dead paraffinic crude oil at specific salinities.

The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead crude core floods with a live crude core flood. A control experiment pressurizing oil with nitrogen at the same condition, 1100 psi did not show enhanced relative surfactant solubility in the oil phase.
Abrasive Jet Perforating and Fiber-Enhanced Proppant Plug Isolation Improve Efficiencies in Multistage Horizontal Completions
Authors: Itibrout Tarik , Blevins John , Yates Malcolm , Taboada Juan Pablo , Trummer Sascha
Published: February 2011

The process of abrasive jet perforating deployed on coiled tubing (CT), fracturing down the CT and casing annulus, and isolation with proppant plugs has proven beneficial in reducing completion costs and improving operational efficiencies in multistage stimulation applications. Unlike conventional plug and perforation techniques, this process can be done in a single trip, allowing the well to be put on production immediately after the treatment because no bridge plugs have to be drilled. However in horizontal well applications, achieving isolation with proppant plugs can be very challenging due to gravity effects, proppant plug integrity concerns, and ease of fracturing the formation. Adding degradable fibers to proppant plugs has proven successful in achieving good isolation between stages in horizontal wellbores. The fibers not only help create bridging at the perforations, but they also keep the proppant from settling to the bottom of the pipe thereby maintaining the integrity of the proppant plug. This approach has been used successfully in several abrasive jetting fracturing treatments in horizontal wells in West Texas and Southeast New Mexico. Well completion times have been reduced from over a week to only two to three days while allowing for more intervals to be selectively stimulated. Initial production results from the wells completed with the new technique have considerable improvement compared to previous stimulation methods.