bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Shear-Wave Anisotropy To Optimize Reservoir Drainage and Improve Production in Low-Permeability Formations in the North of Mexico
Authors: Franco J. L. A. , de la Torre H. G. , Ortiz M. A. M. , Wielemaker E. , Plona T. J. , Saldungaray P. , Mikhaltseva I.
Published: December 2007

Shear waves propagate through rock with different velocities in different directions. This phenomenon is called acoustic anisotropy, and it is caused by the anisotropic nature of the rock's elastic properties. All sedimentary rocks exhibit some degree of acoustic anisotropy related to aligned fractures, layering, or stress imbalance. Until recently, wireline sonic tools were able to measure the anisotropy magnitude and orientation reliably only if the velocity anisotropy was greater than 5%. In this paper, we will discuss the field test results from multiple wells of a new sonic tool that is able to measure anisotropy as low as 1%. We will also comment on how to identify the cause of the anisotropy and its applications. Because we can measure the acoustic anisotropy with this new tool—even if it is very low—and relate it to the earth-stress direction, we are able to provide reservoir engineers with valuable information to optimize the field development and improve well production.

The tests were conducted in several Pemex development wells in northern Mexico, mostly in the Burgos basin. The target formations were tight gas sands. The sands have very low permeability and must be stimulated to produce hydrocarbons in commercial quantities. These hydraulically fractured vertical wells have elliptical drainage patterns, and optimum reservoir drainage depends on the correct well placement to avoid creating interference between wells (overlapping drainage areas) or leaving areas untouched (drainage gaps). Since hydraulic fractures open in a plane perpendicular to the minimum stress, determining stress direction is crucial to the placement of new wells. Also, it can help to look for in-field drilling opportunities in brown fields where early drilling strategies did not consider the stress orientation when selecting well locations. In addition, by knowing the stress-field state, it is possible to apply oriented perforating techniques to maximize the results of the fracture treatments.
Parallel Scalable Unstructured CPR-Type Linear Solver for Reservoir Simulation
Authors: Cao H. , Tchelepi H. A. , Wallis J. , Yardumian H.
Published: December 2007

We describe a multistage parallel linear solver framework developed as part of the Intersect (IX) next-generation reservoir simulation project. The object-oriented framework allows for wide flexibility in the number of stages, methods and preconditioners. Here, we describe the specific components of a two-stage CPR1 (Constraint Pressure Residual) scheme designed for large-scale parallel, structured and unstructured linear systems. We developed a highly efficient in-house Parallel Algebraic Multigrid (PAMG) solver as the first stage preconditioner. For the second stage, we use a parallel ILU-type scheme. This new and powerful combination of CPR and PAMG was the result of detailed analysis of the linear system of equations associated with reservoir simulation.

Using several difficult reservoir simulation problems, we demonstrate the robustness and excellent parallel scalability of the IX linear solver. For the field case studies, the IX linear solver with CPR and PAMG is at least five times faster than an established and widely used industrial linear solver. The performance advantage of the IX linear solver over traditional reservoir simulation linear solvers increases with both problem size and the number of processors.
Spontaneous Imbibition with Matched Liquid Viscosities
Authors: Fischer H. , Morrow N. R.
Published: December 2007

Laboratory results of oil recovery through spontaneous imbibition are commonly scaled-up to forecast oil recovery from fractured reservoirs. This study addresses oil recovery from cylindrical sandstone cores by spontaneous imbibition at very strongly water-wet conditions for viscosity ratios of unity (a special case of the Mattax and Kyte scaling condition that viscosity ratios be matched). Combinations of mineral oils and aqueous solutions of glycerol were used to obtain matched viscosities ranging from 4 to 172 cp. In all, 25 imbibition data sets are reported for boundary conditions of all core faces open, two ends closed (radial imbibition), and one end open (linear imbibition). The data sets for individual boundary conditions were satisfactorily correlated by the Mattax and Kyte scaling group. Overall correlation of results was obtained after compensating for different boundary conditions by means of a characteristic length. An obvious limitation of correlations based on linear scaling of time is that differences in the shapes of imbibition curves cannot be eliminated. The correlated data provides clear distinction between the overall shape of recovery curves for linear versus radial imbibition.

Final oil recoveries for radially dominated imbibition were independent of viscosity whereas recoveries for linear imbibition were consistently lower and decreased by up to 2.5 % PV with increase in viscosity. Shortly after the onset of imbibition, oil recovery for linear flow is generally close to linearly proportional to the square root of time until the imbibition front reaches the end of the core.
Deepwater Subsea Valve Flow Assurance—Compatibility Between Hydraulic Control Line Fluids and Completion Brines
Authors: Berry S. L. , Ke M. , Baccigalopi G.
Published: December 2007

Proposal

Historically, systematic selection of completion brines for conventional completions has been based on several key critieria: hydrostatic density requirements, true crystallization temperature (TCT), pressure crystallization point (PCT), formation compatibility, and compatibility with reservoir fluid systems. However, as the number of deepwater oil and gas completions has increased, new concerns have arisen about the interaction between subsea hydraulic control-line fluids and completion brine systems. In offshore deepwater applications where subsea valves are not readily accessible, ensuring compatibility of hydraulic control-line fluids and completion brine systems is an essential part of the flow assurance process.

Compatibility issues with completion brines become a concern during the initial seating of surface control units such as a subsea wellhead. All the control lines and orifices are filled with hydraulic fluid prior to running in the well to prevent collapse from subsea pressures. After the units are set in position, excess completion fluid has a tendency to displace the control-line fluid or intermix with it. Intermixing of completion brine and hydraulic fluid is critical because many of these fluids circulate through a extremely small orifice (usually less than 3/16 of an inch). Any precipitation of completion brine salts or separation of hydraulic fluid components may result in plugging and loss of hydraulic control.

This paper will discuss and show results of a laboratory study to investigate compatibility between the most widely used water-based hydraulic fluid systems for subsea control applications and a wide range of completion brine systems. Furthermore, since most hydraulic fluids form insoluble solids when mixed with calcium-based brine systems, recommendation of calcium-based completion brines in deepwater applications has been limited. Therefore, a search for a subsea hydraulic fluid system compatible with calcium-based completion brines was conducted. The paper also outlines the results of a study with a subsea hydraulic fluid found to be compatible with calcium-based completion brine systems and discusses the completion advantages of this system.
High-Porosity Fractures Yield High Conductivity
Authors: Parker M. , Glasbergen G. , Batenburg D. van , Weaver J. , Slabaugh B.
Published: December 2007

Fracture conductivity (FC) in many hydraulic-fracturing treatments being performed can be shown to be inadequate. FC is greatly affected by the concentration of the packed proppant in the fracture. Higher concentrations yield higher conductivity by virtue of a wider fracture. However, there are practical limitations to the amount of proppant that can be placed into any particular reservoir and therefore production is often conductivity limited.

An alternate approach to achieve high conductivity is to create a fracture with high porosity. That is, a fracture with porosity much greater than that possible in a packed fracture. This can be achieved by the placement of well-distributed, low-density particles. The low-density particles may be placed in gelled or ungelled treatment fluids. Low particle concentrations are used to achieve the distribution that provides the high porosity in the fracture.

The theoretical basis for the conductivity of these fractures is presented. A three-dimensional model has been developed to simulate the high-porosity fracture created with particles. Test data used to refine the model can be used to help predict the conductivity of the fracture based on the porosity level, the closure stress, and the material mechanical properties.
The Production Success of Proppant Stimulation on Horseshoe Canyon Coalbed Methane and Sandstone Commingled Wells
Authors: Rieb B. A. , Leshchyshyn T. T.
Published: December 2007

North American demand for natural gas has resulted in attractive commodity pricing and thus a renewed interest in unconventional reserve exploration in Canada. Recent activity in Coal Bed Methane (CBM), or Natural Gas from Coal (NGC), has yielded two primary exploration targets that are promising; one of which is the Horseshoe Canyon coal.

The family of Horseshoe Canyon Coals is shallow and range in depths from about 492 ft (150 m) to 2,789 ft (850 m). Even though broadly referenced as Horseshoe Canyon, the stratigraphic range of the coal is from the Edmonton down to the Belly River formations which includes the Horseshoe Canyon formation. These coals are better described as seams or stringers and are most frequently between 1.5 ft and 5 ft in thickness and generally no more than 9.8 ft in thickness. Reservoir pressures at these depths average from 250 psi (1,700 kPa) to 510 psi (3,500 kPa). Production varies due to the commingling of up to 30 stringers per well bore and total well bore production ranges from 35 Mscf/day (1 E3m3/day) to 636 Mscf/day (18 E3m3/day). Horseshoe Canyon coals are generally accepted to be of very low water saturation, low gas production rates and produce little to no insitu water production upon completion.

The most common completion technique is the sequential stimulation of each stringer by the use of coiled tubing. Marginal gas production and intolerance to completion fluids has resulted in evolution of fracturing systems including binary foamed water, CO2 / N2 proppant, conventional borate water, some hydrocarbon based and pure proppantless nitrogen systems pumped at high rates.

Several issues that are dealt with in this paper include concurrent sandstone and coal perforating and stimulation, and a method for comparing coal to coal and coal to sand production. This paper will be used to examine the incremental sandstone contribution to the overall production of the well. Effect of sanding off the well will be examined as to its impact on production.

The objective of this paper is to present findings of an 18 well pilot study in an ongoing 90 well case study completed in a Horseshoe Canyon development near Red Deer, Alberta, Canada. An paper submission is being chosen, and more updated data will be presented at the conference.
A Semiempirical Model To Calculate Wormhole Growth in Carbonate Acidizing
Authors: Buijse M. , Glasbergen G.
Published: December 2007

The success in matrix acidizing carbonate formations depends entirely on the ability to create long wormholes that bypass the damaged near wellbore region. During the last decade, much progress has been made in the understanding of the physical and chemical processes that determine the final wormhole structure. Several different wormhole models have been proposed in literature. These models are usually successful in predicting wormhole growth under idealized conditions in the laboratory: linear core flow tests, one main wormhole, simple fluids like HCl with known rheology and reactivity, etc. In the design of an acid treatment, however, these models are less useful because they cannot handle the complex field conditions such as: radial flow, multiple wormholes, complex fluids such as emulsified acids or foams, etc.

In this paper, we describe an alternative approach to model wormhole growth. A relatively simple wormhole growth model is developed, that still captures the essential physics and chemistry, and is therefore qualitatively correct. The model is semi-empirical, in the sense that the accuracy depends on two parameters that can be measured in a simple (linear) core flow test. Alternatively, the value of these two parameters can be taken from literature data. In developing the model, the intend was to create a relatively simple tool that can be used by the field engineer to design and optimize an acid treatment, and answer basic questions such as: what type of acid must be used and what is the optimum acid volume and pump-rate?

The paper will describe the details of the wormhole growth model. The wormhole model was embedded in a comprehensive near wellbore flow simulator to analyze wormhole behavior in more complex environments, such as multi-layered reservoirs and long horizontal wells. The model has been used with good success in the design of many carbonate acid treatments. Several examples will be discussed in the paper.
A New Experimental Method to Determine Interval of Confidence for Capillary Pressure and Relative-Permeability Curves
Authors: Egermann P. , Lombard J.-M. , Fichen C. , Rosenberg E. , Tachet E. , Lenormand R.
Published: December 2007

The saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type.

In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale.

The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs.

Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments.
A Rheological Model for pH-Sensitive Ionic Polymer Solutions for Optimal Mobility-Control Applications
Authors: Huh C. , Choi S. K. , Sharma M. M.
Published: December 2007

Polyelectrolytes are water-soluble polymers that form molecular networks by association in solution. The properties of such polymers are very sensitive to the pH and ionic content of the solution. Polyelectrolytes such as poly(acrylic acid) can swell up to ∼1,000 times of its own volume by retaining a huge volume of water, or they may reversibly deswell to their original volume. Their solution viscosity can accordingly be changed by several orders of magnitude in a controlled manner by adjusting the solution pH. This remarkable property of pH-sensitive polymers can be exploited for a number of improved oil recovery (IOR) applications, as proposed by Al-Anazi and Sharma (2002). A key advantage for polyelectrolytes such as poly(acrylic acid) is their very low cost, because immense quantities are manufactured annually for consumer and industrial applications. For IOR processes, such as surfactant flooding, CO2 flooding and alkaline flooding, a major technical challenge is to bring the injected chemicals into contact with the oil and to properly herd the mobilized oil to producers, minimizing the undesirable influence of reservoir heterogeneity. Placement of the mobility control polymer in desired locations in the reservoir for controlled viscosification can significantly alleviate the problem of volumetric sweep. For the optimal control of the polymer viscosity at the desired locations, the dependence of the polymer rheology on pH, salinity, polymer concentration and molecular structure needs to be known accurately. The rheology correlation can then be employed for IOR process simulations for optimal design of mobility-control bank placement and viscosification, and for evaluation of its effectiveness.

A comprehensive rheology model is developed by combining the ionic hydrogel swelling theory of Brannon-Peppas and Peppas (1988) with the Mark-Houwink equation that relates the polymer intrinsic viscosity with polymer molecular size; the Martin equation that relates the characteristic Newtonian viscosity with polymer concentration and intrinsic viscosity; and the Carreau equation that relates polymer viscosity with shear rate. The ionic swelling theory had been independently validated with laboratory swelling experiments earlier, and the Mark-Houwink, Martin, and Carreau equations have been employed to characterize aqueous polymer solution rheology. The polymer solution viscosity can, therefore, be reliably predicted as a function of pH, salinity, polymer concentration, and shear rate. The model predictions match the laboratory-measured viscosity data reasonably well, for a range of pH, salinity, polymer concentration, and shear rate. The model is presented in a form that can be implemented in an IOR process simulator for optimal mobility control applications, as described above.
Evaluating Barnett Shale Production Performance Using an Integrated Approach
Authors: Frantz J. H. , Williamson J. R. , Sawyer W. K. , Johnston D. , Waters G. , Moore L. P. , MacDonald R. J. , Pearcy M. , Ganpule S. V. , March K. S.
Published: December 2007

This paper presents the results of using a shale-specific, finite-difference reservoir simulation model to history match and forecast production data from the Barnett Shale reservoir. The paper will illustrate the many uses of the model for vertical and horizontal wells including determining gas in place, recovery factors, optimal well spacing, drainage areas and drainage shapes, optimal fracture half-lengths and conductivities, infill evaluations, horizontal well modeling and optimal number of stimulation treatments, analysis of microseismic data, and compression evaluations. The model was developed in the early 1990s to incorporate all of the production mechanisms inherent in shales including matrix gas porosity, gas desorption isotherm, single-or two-phase flow of gas and water in the natural fractures, layers, complex hydraulic fractures, and variable flowing bottomhole pressures. The paper will discuss the methodology to incorporate all field data into the simulator including core, logs, well test, completion, stimulation, microseismic, and production data. Examples will be given using public datasets. We also show production comparisons between vertical and horizontal wells since this is of topical interest in the play's development history. Furthermore, we discuss the various types of data to collect, their importance to proper stimulation design, and the integration methodology to evaluate and complete shale reservoirs.
Why Don't We Pump More Type I/II Lightweight Slurries?
Authors: Myers R. R.
Published: December 2007

For nearly two decades in the Appalachian Basin many hundreds of Type I/II lightweight cement slurries with reduced compressive strengths, and increased elasticity have been successfully applied to Devonian Shale wells. More recently, hundreds of reduced density slurries have been successfully pumped on surface and intermediate casing jobs. Despite this success, the majority of new cement bid requests in the Northeast Region and perhaps across the U.S. for that matter still specify API monogrammed cement. The reality for the Northeast U.S. is that no cement plant within 450 miles manufactures to the API specification, except LaFarge at their Joppa facility. Plants manufacturing to API specification turn out a product that may vary more greatly batch to batch than the Type I/II cements. So much for uniformity and consistency, the most valued advantages of API cement.

The situation begs the question: Why are drilling engineers so reluctant to pump more cost saving Type I/II lightweight slurries if they meet the technical criteria and are clearly more cost effective? One reason may be regulatory; state oil & gas code books were written years ago specifying API cement and compressive strength requirements for many applications. Another is awareness, many State Oil & Gas Regulatory Agencies may not know about the recent advances in oilwell cements, nor the fact that API cement is not available in their area of responsibility.

This paper will lay out the case for Type I/II lightweight cement slurries, how they have superior mechanical properties for long term zonal isolation, and some example applications best suited to them. Supporting technical data includes cost savings and case histories of some applications. Efforts to educate the state regulatory agencies along with an example of successful requests for variances will be presented.
Comprehensive Performance Design Criteria for Hydraulic Fracturing
Authors: Manrique J. F. , Poe B. D.
Published: December 2007

Several works have tried to address hydraulic fracturing treatments using a unified theory approach based on the dimensionless productivity index concept. The observations and recommendations from these works are based on numerical simulation, resulting from single phase liquid and simplifications such as steady state or pseudo steady state conditions. However, the behavior in the reservoir is not a simplified one and the assumptions made previously by other authors limit the application of the technique.

In this paper we present the correct and rigorous mathematical solution of the dimensionless productivity index. The application of a General Expression for Dimensionless Productivity in Bounded Reservoirs is presented and applied to multiwell systems

Field examples and results are presented, where production analysis suggested changes and optimization of fracturing fluids, breakers, job sizes, designs, types and mass of proppant, etc. Guidelines for performance optimization and practical standards are obtained from field production results and are also presented.
Liquid Lifting From Natural Gas Wells: Tubing-Casing Junction
Authors: Christiansen R. L. , Girija E. , Riggins L. , Elsener G. , Sutton R. P. , Smeenk R.
Published: December 2007

Effective removal of water and hydrocarbon liquids from gas wells can maintain and increase gas production. In this paper, results of flow loop tests on transport of liquid from casing to tubing is reported for flow rates ranging from 50% below to 50% above the critical gas flow rate for the tubing. The results show that liquid transport is severely constrained at the tubing-casing junction because the gas flow rate is usually much below the casing critical flow rate. To resolve the tubing-casing bottleneck, six approaches were tested: constrictions in the tubing, a vortex-generating device in the tubing, an assembly of baffles in the casing, a ball pack in the casing, a closed-end pipe in the casing, and foam-generating surfactants. The first two approaches provided no benefit. The last four approaches enhanced liquid lifting, in some cases by a factor of 10 or more. All approaches that increase liquid transport from the casing to the tubing also increase pressure gradient. Approaches that boost liquid transport rate with a small increase in pressure gradient are most desirable.
Streamline Tracing on Unstructured Grids
Authors: Sun S. , Gai X. , Wheeler M. F.
Published: December 2007

Traditional methods for streamline tracing are mainly based on the Pollock Cartesian scheme and its extensions, which require dual grids to treat general tensor fields on unstructured meshes. The complexity and inflexibility of dual grids impose substantial limitations on the application of streamlines.

In this paper, we propose a computationally efficient method to construct streamlines on the original grid, taking flow fields from arbitrary schemes including Galerkin finite element methods. An essential component of the proposed streamline construction is fast processing of non-conservative velocity fields to recover or maintain local mass conservation and normal flux continuity simultaneously. Our construction involves balancing conservation residuals on each pair of adjacent elements using a Gauss-Seidel type iteration. Locally conservative velocities are extended from element faces to interiors using a local single element mixed finite element method. Streamline and travel time are then obtained using standard methods of integration based on the Pollock algorithm.

The proposed approach is shown to possess several advantages: it treats general tensor fields on unstructured and even nonmatching grids, maintains the optimal order of accuracy for high order elements, and avoids the difficulties imposed by nonphysical sinks and sources due to numerical inaccuracy. Several computational examples on structured and unstructured meshes are presented to demonstrate the effectiveness of the proposed method.
Reservoir Characterization of Fractured Cambrian Reservoirs, Algeria
Authors: Guehria F. M. , Yawanarajah S. , Touami M.
Published: December 2007

It has long been recognized that the faults in the Hassi Messaoud field are necessary for the successful production from the Cambrian sandstone reservoirs. What is less understood is the dual nature of these faults in that they can both control transmissibility through permeability enhancing fractures, and control trapping (sealing) through permeability reducing diagenesis. The key to optimally exploiting this or any fractured reservoir is the ability to predict the existence and properties of both. Without these faults and fractures, the Cambrian reservoirs would be classified as being tight with matrix permeabilities that are less than 40 mD, usually less than 3 mD, and porosities of between 3-8 %. In addition, the production history of the wells indicate variability in matrix versus fracture contribution, which suggests that the field was composed of more than one type of storativity-based, fractured reservoir.

An integrated reservoir characterization study was conducted in Zones 1A and 1C to confirm the above premises. Reservoir quality and compartmentalization of the Cambro-Ordovician Ra and Ri reservoirs are believed to be related to stratigraphic, diagenetic, and structural variability. There is much evidence for reservoir heterogeneity especially around faults i.e. variation in reservoir thickness, rapid changes in porosity and permeability, variable production performance, variable water production. There is also evidence that fracture intensity varied from north to south and that this affected well performance. A number of wells were picked for detailed evaluation based on their production history and proximity to faults.
Continuous Model Update of Natural Fractures Characterization in Sinan Field To Optimize Production
Authors: Solís R. , Cabrera C. , Liévano R. , Monroy F. , Cruz G. , Saputelli L.
Published: December 2007

In this paper, we show the case history for the characterization of the naturally-fractured light oil reservoir, Sinan, which is located in the Gulf of Mexico continental shelf, at 40 km north of Frontera port, state of Tabasco, Mexico.

Historic production test data from preciously drilled wells showed tremendous well productivity variation as function of well location, and trajectory design.

We built a complex 3D structural framework with the use of static and dynamic information. Up-to-date well drilling data was used to continuously calibrate the model as well as 33 km2 processed seismic information. The resulted framework was derived from the integration of two seismic cubes (time and depth post-migrated), resistive image logs, sonic logs, dipolar logs, core information (petrophysical data), well testing, and geological information. This model provides a quantitative framework for the spatial distribution of subsurface properties of the Sinan Field.

As a result of the applied methodology, drilling trajectory and target of proposed development wells were reconsidered. Recommended proposals as a result of this study allow better reservoir fluid contribution which increase and optimize production. The resulted model will be continuously updated to support the drilling of approximately 5 wells per year to fulfill field development requirements.
PS Reflections in Seismic Data
Authors: de Bruin J. A. , Chahine A. A. , Wijnands F. M.
Published: December 2007

Offset VSP data in the Deir Ez Zor area contains significant mode-converted shear wave energy. This allows us to obtain two results: a P-wave and an S-wave OVSP image. The additional information contained in the shear wave image can significantly aid interpretation. There are however differences in character, amplitude and polarity. Interpreted in conjunction with Zoeppritz equation modeling, these can provide information about lithology and fluid content that cannot be extracted from P waves alone.

We now believe, based mainly on evidence from offset VSP data, that part of the noise in our surface seismic consists of mode converted shear waves, rather than P-wave multiples. NMO velocities and AVO anomalies in prestack surface seismic data corresponded with modeled PS responses. Such modeling thus provides a method of identifying suspected PS reflections in the vicinity of wells with OVSP data or full waveform sonic and density logs. Depending on the importance of a particular event, if there is a suspicion that it may be a PS reflection, it will often be justified to obtain OVSP data and to re-evaluate pre-stack surface seismic data.
Advances in Integrated Horizontal Production Logging in Openhole Completions
Authors: Al-Ismail M. S. , Zeybek M. , Kelder O. , Al-Muthana A. S. , Mubarak S. , Abdulrahman A.
Published: December 2007

Production logging, especially in highly deviated, horizontal wells still exhibits challenges due to multi-phase, complicated flow regimes in undulating long well bores in open hole completions. Because of the advances in measurement technology and interpretation techniques, production logging objectives can be achieved in more challenging conditions; the improved confidence in the result is crucial to associated decisions and well interventions.

In this paper, we present four field examples that used the latest technological advances and the best practices in integrated production logging in horizontal wells with openhole completions using either coiled tubing or tractor conveyance. The first example detected a super-permeability zone and a changing water salinity profile in the wellbore. The second example identified crossflow in a shut-in multilateral well; subsequent workover revived the oil production to initial production levels. The third example provides a discussion of the effective design of tractor-conveyed horizontal production logging to identify water entry and define the flow profile. The last example relates the first use of a new, compact, integrated production logging tool that pinpointed water entries in a horizontal openhole completion. This compact production logging system provides comprehensive, continuous data for the analysis of complex horizontal flow behavior.

The results of these field examples show how the application of the latest advances in horizontal production logging operations can significantly improve our understanding of well behavior and reservoir characterization. Combining these advantages with effective remedial action and workover operations can increase production and extend the life of horizontal openhole producing wells.
Accelerated Well Delivery through High Performance Directional Drilling Systems—A Middle East Case History
Authors: Vestvik J. , Andersen T. , Istad N. , Rattray E. , Sutcliffe B. , Craig C.
Published: December 2007

An integrated drilling system, custom designed to optimize drilling performance on the World's largest proven offshore gas field, has produced a step change in drilling performance resulting in reducing the overall planned spud to total-depth drilling by half.

This paper will focus on how this exceptional performance was achieved with specific focus on the new-generation positive displacement motor (PDM) and PDC bit combination and the "performance directional drilling" techniques employed.
Physio-Chemical Characterisation of Vegetable Oils and Preliminary Test Results of Vegetable-Oil-Based Muds
Authors: Amanullah Md.
Published: December 2007

Mineral oil-based drilling muds are toxic, not readily biodegradable and thus have cumulative impact on terrestrial, coastal and marine habitats. The base fluid for mineral oil-based mud development has limited source of supply. Vegetable oils are renewable, highly biodegradable, can be produced as per industry demand and thus could be a suitable candidate for development of a highly biodegradable oil-based mud with a sustainable source of supply. They have higher flash and fire points, better thermal stability, no detrimental impact on the surrounding environment and are much less hazardous compared to mineral oils. Due to biodegradable nature of vegetable oils, drill cuttings will have no environmental impact if the cuttings are disposed directly to the surrounding environments. Due to non-reactive nature of vegetable oils with clays and shales, their technical performance in maintaining borehole stability is comparable to mineral oil. On the other hand, due to readily biodegradable nature and negligible toxicity effect, vegetable oil-based mud performance should be comparable to water-based mud from environmental point of view. Hence, vegetable oil-based mud could be a potential solution to meet the current as well as future technical and environmental challenges.

An invert emulsion mud was developed using a blend of vegetable oil to study the rheological and filtration properties and evaluate its suitability for oil well drilling. Initial mud formulation indicates that development of a viable OBM is not possible using the conventional approach due to the high inherent viscosity of vegetable oils and significant thermal degradation at high temperature. However, processing and treatment of vegetable oils lead to the formulation of a vegetable oil-based mud with desirable rheological properties and excellent thermal stability. Preliminary test results indicate that the processed vegetable oil-based mud produces suitable low end rheological properties including gelling characteristics. Thermal conditioning of the mud at 150 °C for 16 hours indicates no significant changes in the rheological properties of the mud. The high thermal characteristics of vegetable oils indicate their safe operation for all practical range of temperatures.
A Critical Comparison of Real Option Valuation Methods: Assumptions, Applicability, Mechanics, and Recommendations
Authors: Bratvold R. B. , Laughton D. , Enloe T. , Borison A. , Begg S.
Published: December 2007

More than thirty years after the debut of the famous Black-Scholes option pricing formula, and more that twenty five years after Stewart Myers coined the term, real option valuation has yet to catch on at most companies in the upstream petroleum industry as part of the asset decision-making process.

While there is a great deal of agreement about the appeal of the underlying ideas, a variety of contradictory implementations, many of which are ill founded or poorly constructed, have been suggested for putting real options into practice. The resulting confusion has made an already difficult problem of diffusion of innovation even more difficult.

In this paper, we build on the work done at the SPE workshop on valuation held in Banff in 2003 to create a detailed taxonomy of the various approaches to real options valuation that have been proposed, and use this taxonomy to compare the different methods. The comparison uses, as an example, an offshore production drilling decision that is realistic on a business level both in structure and data.
Taming Complexities of Coupled-Geomechanics in Rock Testing: From Assessing Reservoir Compaction to Analyzing Stability of Expandable Sand Screens and Solid Tubulars
Authors: Kanj M. Y. , Abousleiman Y. N.
Published: December 2007

Well geomechanics and "smart" completion designs in many of Saudi Aramco's fields are essential to support the company's efforts to apply the extended-reach and MRC well technologies. MRC wells are being aggressively targeted to optimize development economics, enhance recovery, maximize production, minimize differential drawdown across the sand face, reduce sanding potential, and defer water coning. In addition, many unconsolidated sandstone reservoirs require positive sand control measures. As such, Expandable Sand Screen (ESS) tubulars have seen a recent surge in applicability for completing conventional and MRC wells in sand prone, troublesome formations. Today, solid expandable tubulars are being tested on a number of wells in a pseudo mono-diameter structure. Though attractive, the long-term performance of these tools in the arabian reservoir environments is yet to be explored.

This paper simulates the impact of reservoir production and depletion on expandable tubulars and sand screen completions when the compacting reservoir behaves as a permeable poroelastic medium. A general poroelastic solution model encompassing a multitude of boundary and initial conditions is discussed in this paper. The model simulates the uniaxial (Ko) testing of solid and hollow ge-omaterial cylinders (Geertsma, 2005). Thus, it helps infer about potential problems that might influence the survivability of "expandables" and disrupt the outflow from the well. The herein presented proof cases on reservoir and cap rocks are supported with numerical application, experimental validation, and physical interpretation of the coupled poromechanical processes that are reflected in the anisotropic, time-dependent rock responses during testing. The manuscript also demonstrates that this enhanced approach to modeling visualization will ultimately ease the tractability of the pertinent physical phenomena as well as support the model's computational credibility to engineers and experimentalists in the oil and gas industry.
Tuning of Computer Model Parameters in Managed-Pressure Drilling Applications Using an Unscented Kalman Filter Technique
Authors: Gravdal J. E. , Lorentzen R. J. , Fjelde K. K. , Vefring E. H.
Published: December 2007

In order to manage the annular pressure profile during Managed Pressure Drilling (MPD) operations, simulations performed with advanced computer models are needed. To obtain a high degree of accuracy in these simulations it is crucial that all parameters describing the system are as correct as possible. A new methodology for real time updating of key parameters in a well flow model by taking into account real time measurements, including measuring uncertainty, is presented. Key model parameters are tuned using a recently developed estimation technique based on the traditional Kalman Filter.

The presented methodology leads to a more accurate prediction of well flow scenarios. Although the present study is motivated by applications in MPD, the idea of tuning model parameters should be of great importance in a wide area of applications.

The performance of the filter is studied, both using synthetic data and real measurements from a North Sea High-Pressure-High-Temperature (HPHT) drilling operation. Benefits by this approach are seen by more accurate downhole pressure predictions which are of major importance for safety and economic reasons during MPD operations.
Deep Directional Electromagnetic Measurements for Optimal Well Placement
Authors: Omeragic D. , Li Q. , Chou L. , Yang L. , Duong K. , Smits J. , Lau T. , Liu C. B. , Dworak R. , Dreuillault V. , Yang J. , Ye H.
Published: December 2007

A new logging-while-drilling (LWD) tool that incorporates directional antennae and long measurement spacings has been developed and field tested. The directional electromagnetic (EM) tool measurements are more sensitive to approaching resistivity boundaries than existing propagation resistivity tools. Combining measurements from symmetrically arranged pairs of antennae further amplify this boundary effect while minimizing undesirable sensitivity to dip and anisotropy. Novel data processing and structure visualization software was developed to aid the decision-making and planning process. Field test results from Oman and the North Sea illustrate how the directional EM measurements fulfill the requirements for geosteering in thin, dipping, and curving targets with lateral resistivity variations. In addition, the directional EM tool also enables improved characterization of resistivity and resistivity anisotropy in high-angle and horizontal wells.
A Timestepping Scheme for Coupled Reservoir Flow and Geomechanics on Nonmatching Grids
Authors: Gai X. , Sun S. , Wheeler M. F. , Klie H.
Published: December 2007

This paper presents numerical techniques for coupled simulations with different time scales and space discretizations for reservoir flow and geomechanics. We use an explicitly coupled approach together with an iterative coupling to increase stability and reduce time discretization error. An error indicator is proposed to determine when displacement must be updated and whether the explicit or iterative coupling technique is required. Under this setting, one geomechanics calculation is performed for several reservoir flow steps. For time steps without geomechanics updates linear extrapolated pore volume is used for porous flow calculations. The resulting algorithm is computationally more efficient than the iterative coupling, and it is more stable and accurate than the loosely coupled technique.

In the event that different meshes are used for the reservoir flow and geomechanics models, special treatments are required for the integration of the coupling terms over each element. To avoid complex 3D grid intersection calculations we propose to divide an element into a number of subelements and apply the midpoint integration rule over each subelement. Numerical results are presented to demonstrate the efficiency and accuracy of the proposed method for coupled simulations with different time and space discretizations.
Permanent Microseismic Monitoring System in a Long Horizontal Well
Authors: Rod M. H. , Zyweck M. , Dorn-Lopez D. W. , Frederiksen C. H. , Gaucher E.
Published: December 2007

A permanent microseismic monitoring array has been installed in a horizontal well with the objective of imaging propagation of acid fractures and water injection fractures in offset wells. The array consists of 16 geophones placed at 500 ft intervals along the horizontal section of a producing well, deployed inside the pre-perforated liner and coupled to the formation by gravity. Optimal monitoring conditions are achieved when production from the well is closed in, however, many events have been detected whilst the well is producing by applying a production noise filter. Microseismic events are detected, one per week on average, when the monitoring well is producing and 1-2 events per day when the well is shut in.

The microseismic monitoring well is located in the Halfdan field in the Danish North Sea. This chalk reservoir has been developed with a line drive waterflood configuration, alternating oil production and water injection wells. Parallel horizontal producers and injectors are drilled in the direction of maximum horizontal stress, 600 ft apart with reservoir completions in the range 10,000–15,000 ft. The relatively close well spacing is necessary to maximise recovery from the tight chalk reservoir. Multiple acid fractures are placed in producing wells to maximize productivity while fractures are induced by water injection in injection wells in order to achieve voidage replacement. Orientation of induced fractures along the direction of the horizontal wellbore is critical to avoid early water breakthrough and inefficient sweep patterns.

Approximately 450 microseismic events have been located from a total of 13 acid fracture stimulation treatments in two offset producers, both 1,200 ft from the monitoring well. Definitive fracture orientations have been determined for 8 acid fracture stimulation treatments. Contrary to expectations, the fractures have propagated orthogonally to the wellbore. This has resulted in a modification in the completion methodology for subsequent Halfdan producer wells. Water injection fractures have not been imaged with the microseismic network.
The Impact of Proppant Retardation on Propped Fracture Lengths
Authors: Gadde P. B. , Sharma M. M.
Published: December 2007

A model for the velocity of proppant particles in slot flow is presented. The proppant is either retarded or accelerated relative to the fluid depending on the ratio of the proppant size to the fracture width. It has been found that when this ratio is small, the proppant travels faster than the average fluid velocity at that location because the proppant tends to be confined to the center of the flow channel where the fluid velocity is higher. As the proppant size increases, the effect of the fracture walls becomes more important and the proppant is retarded by the walls. The retardation of particle relative to the fluid is greater for larger particles and greater proximities to the fracture walls due to the hydrodynamic stress exerted on the sphere by the walls in the narrow gap. A higher proppant concentration restricts the area available to flow and increases the drag forces on the particles.

A model is presented for the effect of fracture walls and proppant concentration on proppant transport. The effect of this increased drag force is accounted for by modifying the wall - particle interaction. The influence of the surrounding proppant spheres on the drag force on a particle is estimated from the effect of a wall on the drag force acting on a single particle. The equivalent hydraulic diameter is then used to determine the proppant retardation. The effects of wall roughness and fluid leakoff are discussed. Models are suggested that capture these first order effects.

The new model for proppant retardation has been incorporated into a 3D fracture simulator. Results show that the proppant placement is substantially different when proppant retardation/acceleration is considered. Comparisons of propped fracture lengths obtained with the new model agree much better with propped and effective fracture lengths reported in the field.