bluuebunny/crossref_metadata_2025 huggingface dataset:
Pattern-Based Approach to Multiphase Flow Upscaling Using Distance-Based Clustering
Authors: Suzuki Satomi
Published: October 2011

Methods for multiphase flow upscaling have been investigated and proposed by numerous researchers for decades. However, technologies to generate pseudo relative permeability and assign them to simulation gridblocks have not yet reached maturity in terms of both robustness and practicality. The major limitation of dynamic pseudo function methods is that they generate as many pseudo relative permeability curves as number of simulation gridblocks, which is not manageable in real field applications. To overcome this drawback, several methods for grouping pseudo relative permeability have been proposed. However, they are either 1) computationally expensive and in need of running flow simulation or streamline simulation on every simulation gridblock, or 2) devised for ensemble-level upscaling and do not intend to preserve multiphase flow behavior on a single model basis. A practical and efficient method that can facilitate multiphase flow upscaling in routine workflow of reservoir simulation is desired.

This paper proposes a new multiphase flow upscaling technique using pattern-based approach. By utilizing a fast static algorithm, a subgrid scale profile of displacement front is rapidly generated for each of simulation gridblocks based on finescale geological description. The simulation gridblocks are grouped into clusters in accordance with the similarity of the pattern of displacement front profile in subgrid scale. Computationally efficient data mining methods that use distance-based clustering techniques are applied for the grouping of numerous gridblocks. All simulation gridblocks belonging to the same cluster can share the same pseudo relative permeability because of the strong correlation between displacement front profile and pseudo function. The method is developed in the context of local boundary condition based upscaling method so that pseudo functions are independent on gridblock positions relative to wells and fluid contacts.
MPD - Drilling Optimization Technology, Risk Management Tool, or Both?
Authors: Hannegan Don M.
Published: October 2011

Managed Pressure Drilling (MPD) was introduced to offshore drilling decision-makers in 2003. To garner industry attention, it was taught in a "let me show you the money" style with a focus upon its ability to mitigate the types of drilling challenges that often manifest excessive drilling non-productive time (NPT), high mud costs and failure to reach the total objective with large enough hole for optimum well productivity.

Hundreds of offshore applications have now been safely and effectively practiced from all types of offshore rigs. Compared to offset wells, NPT and mud costs are reduced significantly. Otherwise technically or economically un-drillable prospects have been drilled, increasing recoverable reserves in operator's business units. There have been no reportable well control incidents where the root cause has been attributed to the technology itself or failure of its key enabling equipment. All operators’ business units who have practiced MPD, however conservatively as an early adopter, appear to have no reservation about applying it again on challenging prospects that may benefit from its hallmark – optimizing the drilling process by precise management of the wellbore pressure profile. There is no doubt that MPD has "showed the money".

However, its track record has demonstrated other strengths of significance in today's drilling environment. MPD is being recognized as a risk management technology applicable to complex prospects whose drilling hazards, if not mitigated with best available technology, increase the risk of a well control scenario developing and time for "something else to go wrong". Un-mitigated drilling hazards may also contribute to the well being over budget and behind schedule - a human factors climate which tempts short cuts and cost savings later in drilling program and plugging & abandonment (P&A) operations that are not peer-reviewed or thoroughly vetted for added risk and potential HSE consequences.

This paper will provide evidence in the form of case studies that suggest the industry consider the positive effects on drilling costs and increased recoverable reserves as welcome by-products of MPD applications but not necessarily the primary objective of its application.
Effects of Temperature Variations on Formation Tester Pretests
Authors: Betancourt Soraya S. , Dussan V E. B. , Lake Larry W.
Published: October 2011

To date the analysis of pressure transients associated with formation tester pretests assumes that the temperature remains constant during the measurement. Most fluids experience a decrease in temperature when undergoing an expansion, as in the case of the drawdown; therefore, it is to be expected that the temperature of the fluid within the flowline of the formation tester will change for typical pretest conditions. The object of this study is to assess the impact of these temperature transients on the pressure signal measured with single probe formation testers.

The governing equations to analyze pressure and temperature changes in the flowline have been identified. The semianalytic solution presented here couples conductive heat transfer with conservation of mass in the flowline. Sensitivity studies and practical applications are provided to illustrate the importance of thermal effects on the pressure signal recorded during the pretest. It is demonstrated theoretically that in addition to the pretest parameters (rate and volume) and tool parameters (probe size and flowline volume), the specifics of the formation tester design and environmental conditions (pressure, temperature, type of drilling fluid) are relevant to quantify the impact of temperature effects on the measurement of sandface pore pressure with a formation tester.

It has been found that the rate of thermal equilibration during the buildup could affect the behavior of the pressure signal. In particular, thermal effects may extend the duration of the flowline storage period. The two major consequences are: 1) longer time could be required for the flowline pressure to equilibrate to the sandface pore pressure; and, 2) it is possible for flowline storage effects to mask the deep formation response, e.g., spherical flow, in the late part of the buildup. The latter could introduce errors in the interpretation of the buildup pressure signal to obtain formation mobility. Other situations of practical interest, such as "false buildups" after a dry pretest, and "builddowns", i.e., a decrease in the pressure signal after an overshoot beyond the sandface pressure during the buildup, are also addressed here.
Computation of Productivity Index with Capillary Pressure Included and Its Application in Interpreting Production Data from Low-Permeability Oil Reservoirs
Authors: Li Kewen , Chen Zengwei
Published: October 2011

Capillary pressure might be ignored in high permeability rocks but could not be neglected in low permeability rocks. In order to study the effect of capillary pressure on production performance in low permeability oil wells or reservoirs, the formula of calculating water cut, dimensionless total and oil productivity indices were derived by considering capillary pressure. Productivity index and water cut data were computed using the new models with capillary pressure included. The results proved that the productivity index increases with water cut in high permeability rocks but decreases with the increase in water cut within a specific range in low-permeability rocks. Water flooding experiments have then been conducted in core samples with low and high permeabilities. The experimental data also demonstrated the same relationship between productivity index and water cut as the new productivity index model foreseen. Finally the productivity index data were calculated using production data from oil wells and the results were compared with the experimental data of the productivity index determined from core flooding tests. The curves of productivity index vs. water cut obtained from the production data of oil producers were consistent with those inferred from water flooding data in core samples. Note that the core plugs were sampled from the same oil wells. The new productivity index model could be used to explain the difference in production performance between high- and low-permeability oil wells.
Impact of Asphaltene Nanoscience on Understanding Oilfield Reservoirs
Authors: Mullins Oliver C. , Ballard Andrews A. , Pomerantz Andrew E. , Dong Chengli , Zuo Julian Y. , Pfeiffer Thomas , Latifzai Ahmad S. , Elshahawi Hani , Barré Loïc , Larter Steve
Published: October 2011

Understanding asphaltene gradients and dynamics of fluids in reservoirs had been greatly hindered by the lack of knowledge of asphaltene nanoscience. Gravitational segregation effects on oil composition, so important in reservoir fluids, are unresolvable without knowledge of (asphaltene) particle size in crude oils. Recently, the "modified Yen model" also known as the Yen-Mullins model, has been proposed describing the dominant forms of asphaltenes in crude oils: molecules, nanoaggregates and clusters. This asphaltene nanoscience approach enables development of the first predictive equation of state for asphaltene compositional gradients in reservoirs, the Flory-Huggins-Zuo (FHZ) EoS. This new asphaltene EoS is readily exploited with "downhole fluid analysis" (DFA) on wireline formation testers thereby elucidating important fluid and reservoir complexities.

Field studies confirm the applicability of this scientific formalism and DFA technology for evaluating reservoir compartmentalization and especially connectivity issues providing orders of magnitude improvement over tradional static pressure surveys. Moreover, the mechanism of tar mat formation, a long standing puzzle, is largely resolved by our new asphaltene nanoscience model as shown in field studies. In addition, oil columns possessing large disequilibrium gradients of asphaltenes are shown to be amenable to the new FHZ EoS in a straightforward manner. We also examine recent developments in asphaltene science. For example, important interfacial properties of asphaltenes have been resolved recently providing a simple framework to address surface science. At long last, the solid asphaltenes (as with hydrocarbon gases and liquids) are treated with a proper chemical construct and theoretical formalism. New asphaltene science coupled with new DFA technology will yield increasingly powerful benefits in the future.
Mechanical Modeling of Shape Memory Polyurethane Foam for Application as a Sand Management Solution
Authors: Ozan Cem , van der Zee Wouter , Brudy Martin , Vinson Justin
Published: October 2011

Shape memory materials are emerging as a new class of smart materials due to their ability to recover a predetermined shape following environmental changes (e.g., thermal, chemical, magnetic) even after undergoing large deformations. Recently, a thermally activated shape memory polyurethane (SMP) foam has been developed and anticipated to be used as a novel expandable sand control tool.

To understand the SMPs behavior in reservoir conditions, a finite element model to simulate the operational life of the SMP - in-situ deployment of the foam and subsequent depletion of the surrounding reservoir - was developed, and specifics are presented in this paper. A constitutive model based on the concept of phase transitions to describe the thermo-mechanical behavior of the SMP was used along with the Drucker-Prager model to simulate the behavior of the surrounding reservoir.

An operational failure condition for the SMP-reservoir system was defined in which it is considered an operational failure if the foam-wellbore contact is compromised at any point at the foam-wellbore interface during the operational life of the SMP. Using the developed model, a set of simulations for different reservoir conditions was performed. Results show that the performance of the foam is not significantly influenced by the properties of the reservoir and the SMP stays totally conformable during its operational life.
Texas Panhandle Granite Wash Formation: Horizontal Development Solutions
Authors: Rothkopf Brian , Christiansen David J , Godwin Harrison , Yoelin Alan R
Published: October 2011

The Granite Wash formation in the Texas Panhandle is an active horizontal drilling trend where high initial gas rates combined with rich condensate yields create a rewarding investment opportunity for operators. The Granite Wash formation has been a drilling target for over 30 years but development accelerated rapidly after November 2004 when 20-acre downspacing was approved in the Buffalo Wallow field. In the years 2004-2008, vertical infill development was actively pursued with operators using an "assembly line" methodology that concentrated on cost reduction to achieve economic success. When soft gas prices made vertical wells economically challenging, operators turned to horizontal wells to improve the trend's economics. Previous papers [Edwards (2010), Ingram (2006)] have explored optimizing completion technology in the Granite Wash so this paper's objective is to find solutions to questions about initial production, rate decline, and liquid yields by examining the reservoir and fluid properties. The paper uses techniques developed for generalized tight gas sand reservoirs and applies Granite Wash formation data to create focused solutions. The data presented show the horizontal wells’ high initial rates can be correlated to the offset vertical well performance and the initial production declines are defined by linear flow. In addition, a technique for optimizing the number of completion stages is presented and the condensate yields are explained using an Equation of State (EoS).
A New Method for the Design and Selection of Premium / Woven Sand Screens
Authors: Mondal Somnath , Sharma Mukul M. , Hodge Richard M. , Chanpura Rajesh A. , Parlar Mehmet , Ayoub Joseph A.
Published: October 2011

Woven metal mesh sand screens, commonly known as premium screens, have been extensively used by the industry. Sand retention testing is often done to evaluate the performance of these screens and establish empirical guidelines for screen size selection. However, these tests are tedious and the results are prone to artifacts and have been used, at best, to correlate trends in sand retention performance with select sand size distribution parameters. A new method incorporating results from numerical modeling in addition to experimental data is presented to estimate the mass and size distribution of the produced solids through premium screens. This method provides a fast, reliable correlation to estimate sand production through premium mesh screens when the size distribution of the formation sand is known.

This paper presents results from a wide range of sand retention experiments. In these tests the mass of sand produced and its size distribution over time are measured. Results of three-dimensional, discrete element computer simulations of woven screen geometry placed in contact with granular sand packs of ~100, 000 particles are also presented. Based on both the simulations and the experiments a new method for screen selection is presented. This method is based on a correlation that allows us to use the entire sand size distribution of the formation sand and estimate the mass and size distribution of the produced sand. The method is validated by comparisons with experimental data.

A new method and new correlations for estimating the mass and size distribution of produced solids through premium screens is presented. Key differences in sand retention mechanisms between premium and wire-wrapped screens have been identified. The method uses the entire formation sand size distribution (as opposed to a single design point) and has been validated with laboratory tests. The method also helps in screening anomalous test results.
The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embedment
Authors: Akrad Ola , Miskimins Jennifer , Prasad Manika
Published: October 2011

The development of shale reservoirs has grown significantly in the past few decades, spurred by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs is highly dependent on the design of the hydraulic fracturing treatment. In order to successfully design the treatment, a good understanding of the shale mechanical properties is necessary.

Some mechanical properties, such as Young's modulus, can change after the rock has been exposed to the hydraulic fracturing fluids, causing weakening of the rock frame. The weakening of the rock has the potential to increase proppant embedment into the fracture face, resulting in reduced conductivity. This reduction in conductivity can, in turn, determine whether or not production of the reservoir will be economically feasible, as shale rocks are characterized by their ultra-low permeability, and conductivity between the reservoir and wellbore is critical. Thus, shale reservoirs are associated with economic risk; careful engineering practices; and a better understanding of how the mechanical properties of these rocks can change are crucial to reduce this risk.

This paper discusses various laboratory tests conducted on shale samples from the Bakken, Barnett, Eagle Ford, and Haynesville formations in order to understand the changes in shale mechanical properties, as they are exposed to fracturing fluids, and how these changes can affect the proppant embedment process. Nanoindentation technology was used to determine changes of Young's modulus with the application of fracturing fluid over time and under high temperature (300 °F) as well as room temperature. Mineralogy, porosity, and total organic content were determined for the various samples to correlate them to any changes of mechanical properties. The last part of the experiments consisted of applying proppants to the shale samples under uniaxial stress and observing embedment using scanning acoustic microscope.

The results of this study show that maximum reduction of Young's modulus occurs under high temperature and in samples containing high carbonate contents. This reduction in Young's modulus occurs in "soft" minerals as well as the "hard" rock-forming minerals. This reduction of modulus can cause the effective fracture conductivity to decrease significantly.
Transportation and Interaction of Nano and Micro Size Metal Particles Injected to Improve Thermal Recovery of Heavy-Oil
Authors: Hamedi Shokrlu Y. , Babadagli T.
Published: October 2011

Studies on the application of transition metal particles for heavy oil or bitumen up-grading were conducted in the absence of a porous medium, mainly measuring the characteristics of heavy-oil in reaction with metal ions at surface conditions. Dynamic tests on porous media are needed to clarify the injection possibility of the metal particles and their effect on in-situ recovery and up-grading heavy oil. Injection of metal particles may deteriorate the recovery process by damaging porous media due to attractive forces such as van der Waals and electrostatic forces between particles and porous rock. A better understanding of these forces and their importance in the retention of particles is required.

In this paper, the injectivity and transport of nickel particles was studied. The injected suspension was stabilized using Xanthan gum polymer and ultrasonication. The effect of the solution pH, which controls the magnitude of the repulsive electrostatic forces, was clarified. Stabilization of the metal particles suspension was studied at different pH values through zeta potential measurements. Also, the zeta potential of the recovered suspensions was studied to confirm the stability of the suspension during travel through the porous medium. Depending on the size and type, particles carry different charges. Therefore, the stabilization pH and dispersant concentration was different from one sample to another. The results of the injectivity tests confirmed the lower retention of nanoparticles in comparison with micron-sized particles.

A steam simulation process was applied in the presence and absence of metal particles, and heavy-oil recoveries were monitored. Higher recovery was achieved when nickel nanoparticles were used. The changes in asphaltene content and the viscosity of the heavy oil confirm the catalytic effect of the nickel nanoparticles on the in-situ upgrading of heavy-oil.
Extending Production Petrophysics Applications in Monitoring Complex Recovery Mechanisms
Authors: Zett A. , Webster M. , Seccombe J. , Colbert C. , Ansari R. , Chace D.
Published: October 2011

Due to variable reservoir properties, displacement mechanisms and well access issues, cased hole reservoir surveillance for fluid saturation is often challenging. Traditional methods such as capture cross section (sigma) and carbon/oxygen logging are limited in these environments and new techniques are often needed to successfully monitor fluid changes.

This paper discusses the application of two new pulsed neutron based techniques that utilize capture and inelastic gamma ray data acquired with a three detector pulsed neutron instrument. Measurements are combined with theoretically modeled tool responses for different fluids (water, oil and natural gas or carbon dioxide) to determine saturations. Inelastic and capture ratio measurements from the first and third detectors are used because they exhibit higher formation sensitivity than conventional two-detector instruments. These ratios respond differently to changes in oil/gas densities, compositions and formation water salinities, and these differential responses can be used simultaneously to solve for a three-phase saturation solution.

This paper presents results from two mature fields in Alaska. The first example is a three-phase saturation analysis in a light oil reservoir with pressures close to bubble point where traditional sigma and carbon/oxygen logging has been unsuccessful. The new technique located bypassed oil which was produced by adding perforations and confirmed by running production logs. In a second example, the problem was the surveillance of gas cap injection water with seasonal source water salinity variations injecting into a low porosity conglomeratic zone. Trapped gas saturations derived using the new technique were consistent with lab derived core flood measurements. This new generation neutron data has been used to help reduce the range of uncertainty in water salinity and improve the estimation of water saturation within the gas cap even in the low porosity conglomerates.

The new techniques provide an effective solution in environments where conventional pulsed neutron measurements have high uncertainty. Future applications of this measurement in similar areas include the monitoring of reservoirs with complex lithologies where the calibration points are difficult to define and the distinction between gas condensate and dry gas have been problematic for traditional techniques.
Improved Reservoir Characterization through Estimation of Velocity Anisotropy in Shales
Authors: Prasad Tushar , Vines Robert
Published: October 2011

Shales make up most of the sedimentary basins and overlie many hydrocarbon bearing reservoirs. To obtain reliable information on reservoir properties from seismic data, a good understanding of the wave propagation through shales is required. The velocity in shales depends on the direction of wave propagation, as shales are intrinsically anisotropic due to the preferred alignment of clay platelets. This inherent velocity anisotropy in shales must be taken into account for seismic imaging and inversion, seismic-to-well ties, and amplitude variation with offset (AVO) analysis.

Sonic logs provide formation velocities for generating synthetic seismograms, which are subsequently used in the above mentioned seismic analyses. Due to intrinsic anisotropy of shales, the sonic logs in deviated wells can differ from the vertical well response by 30% or more. This needs to be taken into account for accurate seismic analyses. Several methodologies have been developed for estimation of shale anisotropy from deviated-well sonic logs. This paper presents a method to estimate Thomsen's anisotropy parameters from sonic logs as well as density logs in deviated wells.

Three different cases are presented, encompassing exploration, appraisal & development, and production scenarios. Thomsen's anisotropy parameters are estimated using both sonic logs and density logs in deviated wells. When the well deviation is 30 degrees or more, the impact of anisotropy is significant. Accounting for anisotropy provides better confidence in the subsequent seismic analyses. For example, correct VP/VS ratio as an input to AVO analysis ensures improved prediction of reservoir fluid and lithology. Similarly, the synthetic seismograms calculated using anisotropy-corrected velocity logs result in better seismic-to-well ties and seismic inversion.

Field examples illustrate the importance of shale anisotropy quantification for improved reservoir characterization. The use of both sonic as well as density logs to quantify anisotropy has the advantage of taking wave propagation direction as well as compaction into account, and may provide a better local calibration in terms of porosity and burial history.
A Semi-analytical Approach for Estimating Optimal Solvent Use in Solvent Aided SAGD Process
Authors: Gupta Subodh , Gittins Simon
Published: October 2011

SAGD process is widely used to recover heavy oil and bitumen from formations where no other recovery method is proven to be economical. It is an energy intensive process and due to economic and environmental reasons, solvents as additives to the injected steam are currently being explored to reduce energy and emissions intensity of SAGD. The Solvent Aided Process (SAP), tested in field and described in literature, is one such attempt.

In SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam. The viscosity of the oil thus is also reduced due to solvent dilution in addition to heating. SAP can significantly improve the energy efficiency of SAGD, thus reducing the heat requirement as shown in field trials discussed elsewhere. However on the use of right amount of solvent that can result in best overall performance, there is very little discussion in the literature. Due to the high cost of such solvents there is incentive to optimize their use in SAGD. Recently a couple of authors have attempted to address the subject by, for example, using arbitrary time-dependent schemes of solvent injections and assessing their impact on results or treating the internal reservoir dynamics as black-box and using optimization methods such as genetic algorithm to estimate optimal amount of solvent. While these approaches orient us to the problem in a context specific manner, it is believed a generalized treatment to estimate optimal use of solvent requires a mechanism-based understanding.

The approach presented in this paper aims to estimate the optimal solvent in SAGD context. It breaks down the process in its relevant theoretical elements, i.e., a sequential frontal advance with progressive front renewal on account of gravity drainage. This in turn facilitates investigation of a relationship between phase behavior of the solvent, its amount, and the performance of the recovery process. The results are discussed for a few light-alkane solvents.

Better optimal solvent estimates promise to shed light on the supply logistics of these solvents, improve the overall economics and reduce the energy requirements of the heavy oil and bitumen recovery projects.
An Effective Model of Pipe Friction Prediction from Laboratory Characterization to Field Applications for Friction Reducers
Authors: Zhou Jia , Sun Hong , Qu Qi , Bai Baojun
Published: October 2011

Slickwater fracturing technology has been widely used for well stimulation because it is inexpensive and causes relatively little formation damage. Friction reducers are always employed in the slickwater fracturing fluid system due to the high friction pressures resulting from the high rates of fluid injection. Polyacrylamide-based polymer is the most common friction reducer in the industry. Many papers have reported the results of tests on friction reducers in water-based fluids in laboratory-scale straight and coiled tubes, but few have attempted to address the gap between laboratory and field operation data. For example, laboratory tests using conventional fluid rheological parameters do not accurately predict friction reduction when applied to the large pipes used in field operations. Friction reducers’ evaluation using full-scale flow loop testing with tube sizes comparable to those used in field operations are typically expensive and require large volumes of fluids, making them impractical.

This paper describes an attempt to address the gap between laboratory characterizations and field operations, so called "diameter effect". It reports a study of two common friction reducers tested in a laboratory setup. It introduces a new effective model based on fluid velocity profile to reliably predict field friction reduction from laboratory results. The correlation between laboratory and field data is validated by comparing predictions with actual field data from a large number of slickwater fracturing treatments over a wide range of pumping rates and well tube sizes. The study demonstrates that correct lab testing parameters are essential for reliably using laboratory results to predict the effectiveness and performance of friction reducers under field conditions.
Improved Sand Management Strategy: Testing of Sand Monitors under Controlled Conditions
Authors: Emiliani C. N. , Lejon K. , Lindén M. , Engene J. , Kvernvold O. , Packman C. , Clarke D. , Haugsdal T.
Published: October 2011

Sand production has been a constraint to obtain maximized production rates for a number of years for several Statoil fields in the North Sea, due to issues related to: erosion potential not always easy to assess; safe operations: too many uncertainties related to increased sand production; and limited process handling capacity.

Statoil has implemented the Acceptable Sand Rate (ASR), developed together with DNV, as a company strategy for increasing production rates by tolerating sand production within certain limits of maximum allowable sand volume, and maximum allowable erosion in the flow lines and the process system. Although these efforts have resulted in increased production, there is still a way to go to fully utilize the production potential. A key factor with respect to effective sand management is the collaboration and continuous communication among operators and suppliers, and the confidence and methodical approach that engineers and sand monitors’ users should employ supported by a cross disciplinary effort. This paper will present the work carried out jointly by the operator and the suppliers through extensive lab work on the sand monitoring systems available today. The aim of the work is to explore the influence of piping geometry, sand characteristics and fluid/operational conditions on the sand monitors, in a controlled environment, in order to improve their implementation according to the ASR strategy. Instruments, test conditions, CFD analysis, results and conclusions will be described for both acoustic and erosion based monitoring devices.
Lattice Boltzmann Simulation Of Non-Darcy Flow In Stochastically Generated 2D Porous Media Geometries
Authors: Newman M. S. , Yin X.
Published: October 2011

It is important to consider the additional pressure drops associated with non-Darcy flows in the near well bore region of conventional gas reservoirs and in propped hydraulic fractures. These pressure drops are usually described by the Forchheimer equation in which the deviation from the Darcy's law is proportional to the inertial resistance factor (β-factor). While the β-factor is regarded as a property of the porous media, detailed study on the effect of pore geometry has not been done. Many previous experiments and simulations were based on idealized systems such as packings of spheres. In this study, the effect of geometry was studied using a combination of lattice Boltzmann simulations and stochastically constructed 2D porous media models designed to simulate the geometric complexity of reservoir rocks. Based on the data obtained from about 1100 simulations run in 55 model geometries within a porosity range of 8-35%, a dimensionally consistent correlation for the β-factor was established. The effect of geometry on the transition to non-Darcy flow and on the β-factor was evident. It was discovered that the contrast between pore throat and pore body triggers an early transition to non-Darcy flows. Following a quick transition where the correction to the Darcy's law was cubic in velocity, the flows entered the Forchheimer regime where the β-factor increased with decreasing porosity or increasing level of heterogeneity. Inspection of flow patterns revealed both steady vortices and onset of turbulent motions in the Forchheimer regime. The latter correlated well with published point-of-transitions. In developing the correlation for the β-factor, we show that it is necessary to include two distinctive characteristic lengths to account for the effect of pore-scale heterogeneity. This finding reflects the simple fact that it is the contrast between pore bodies and throats that dictates the flow properties of many porous media. In this study, we have used the square root of the permeability and the fluid-solid contact length as the two characteristic lengths, a practical choice when direct measurement of the microscopic length scales is not available. This method can be used in the future to correlate three-dimensional numerical and experimental data.
Fullfield Heavy Oil Conversion from Cold to Hot Production; Challenges and Solutions
Authors: Jansen F. E. , Curtis A. , Mejia-Cana L. V. , Ramsdal J. , Selboe J. O.
Published: October 2011

With an increasing interest for extra heavy oil (EHO) extraction, a number of heavy oil fields will initially be produced using a cold production scheme, while at a later stage thermal production in the form of steam injection can be introduced to enhance the recovery.

Such a fullfield conversion from cold to hot production has so far only been performed to a limited extent, hence the experience and understanding of the various challenges with such a task is limited. While much work has been carried out on both cold and hot production of extra heavy oil as stand alone processes, little has been published around the procedure of converting from cold to hot production.

This conversion contains a number of pitfalls detrimental to a successful field development. In an EHO cold to hot conversion scheme, several choices will have to be made with respect to well positioning, completion options, timing and scale of the conversion. Investment decisions in surface equipment, handling and cost of water and gas for steam generation are also important considerations. All of these designs and decisions affect the success and profitability of the conversion scheme.

One of the basic challenges with modeling cold to hot conversion is the difference in scale required. The thermal simulation of a hot production scheme requires a very fine grid to capture the fine scale processes, while for full field simulation one needs a much coarser grid to be able to obtain a manageable model both in size and simulation time. The high number of producers and injectors required on a fullfield scale adds to the complexity of the problem, making recovery, production profile and optimal number of wells highly uncertain. A simplified translation to fullfield conditions of these parameters from sector models or spreadsheets, can introduce erroneous results and conclusions.

To assure the best field performance over its lifetime, these issues need to be considered already in the initial field design. Based on the work performed, several interesting observations have been made regarding how to optimize field performance.
Practical and Operational Use of Assisted History Matching and Model-Based Optimisation in the Salym Field
Authors: Joosten Gerard , Altintas Asli , De Sousa Paulino
Published: October 2011

History matching and future production optimisation in reservoir modelling is being done more and more with the help of automated or assisted computing techniques, such as design of experiments, Ensemble Kalman Filtering or adjoint- and other gradient-based techniques. With the advent of these techniques, reservoir engineers also get less trivial applications of computer assisted optimisation at their disposal. In this paper we will present two such non-trivial applications.

In the first example we demonstrate how an adjoint-based history match, updating gridblock by gridblock permeability, can flag the problematic areas of a model. The results show that good data matches, requiring unrealistic values for updated parameters are not necessarily useless, but can actually provide a lot of information about unmodelled aspects of reservoir behaviour. Some of the learnings from such an exercise are of geological, others of operational nature. In the second example we use, again adjoint-based, gradients of net present value (NPV) with respect to production and injection rates to optimise well work-over timing. In the field under investigation, each injector well starts its life as a producer, for both geomechanical and operational reasons. Making use of the gradients of NPV with respect to the modelled production rate before the conversion and the modelled injection rate after conversion, the process of shifting the conversion moment forward or backward in time has been automated.

The first example allows for the creation of multiple history matched models, by updating static and dynamic models in parallel, while ensuring the geological concepts are maintained. The second example, well conversion moment optimisation, has been used to validate schedules for operational hoist allocation.

Both applications have had a significant impact on the view of the asset team on the practical usage of modelling: in the first one, a very useful multi-disciplinary platform to help steer thoughts on model improvement was found, while the second helped assess the overall impact of operational decisions on field development.
Lean Synchronization for Turnaround Reduction in Seismic Exploration Programs: The Case of Diaba 3D 6000 km2 Deep Offshore Seismic
Authors: Wabara Kingsley , Petton Ronan , Houllevigue Henri , Garinet Emmanuelle
Published: October 2011

The time, from petroleum exploration work program start dates to the drilling of the first exploration well, constitutes an important constraint on the numerous projects performed during this initial exploration period. Schedule extensions may be negotiated when the going gets tough; but, over the long term, delays in delivering work programs as per initial schedule ultimately imply substantial costs in both cash and reputation; the latter usually in the form of increasing negative perceptions of the enterprise capability to perform. To adapt, industry stakeholders have, in turn, been leveraging principles-guided approaches to cut down on their overall program turnarounds. Lean synchronization, the aim of delivering agreed work programs according to pre-defined quality requirements just-in-time (JIT), and at the lowest possible cost, is one of several means to this end. Using the Diaba 6000 km2 3D full Kirchhoff Pre-Stack Time Migration (PSTM) project as a case study, and within the framework of fixed price plus incentive fee (FPIF) contracts, we conceptualized and implemented a new enterprise project management mechanism principally aligned with the key decision logic for lean synchronization. The results, in all project dimensions, were encouraging: over 50% reduction (from 24 to 9 months) of the pre-bid project execution cycle time; "project-delivery" significantly under budget; and substantial improvements relative to the benchmark product quality.
Decoupling the Mechanisms of Microbial Enhanced Oil Recovery
Authors: Armstrong Ryan T. , Wildenschild Dorthe
Published: October 2011

Microbial Enhanced Oil Recovery (MEOR) is a process where microorganisms are used for tertiary oil recovery. Numerous mechanisms have been proposed in the literature through which microorganisms facilitate the mobilization of residual oil. Herein, we focus on the MEOR mechanisms of interfacial tension reduction (via biosurfactant) and bioclogging in water-wet micromodels, using Shewanella oneidensis (MR-1) that causes bioclogging and Bacillus mojavensis (JF-2) that produces biosurfactant and causes bioclogging. Micromodels were flooded with an assortment of flooding solutions ranging from metabolically active bacteria to nutrient limited bacteria to dead inactive biomass to asses the effectiveness of the proposed MEOR mechanisms of bioclogging and biosurfactant production. Results indicate tertiary flooding of the micromodel system with biomass and biosurfactant was optimal for oil recovery due to the combined effects of bioclogging of the pore-space and IFT reduction. However, metabolic by-products alone were able to recover oil in some cases dependent on wettability. Unaided biomass (i.e. no biosurfactant) that clogged the pore-space also successfully produced additional oil recovery. When analyzing residual oil blob morphology, MEOR resulted in oil blob size and radius of curvature distributions similar to those obtained by an abiotic capillary desaturation test, where flooding rate was increased post secondary recovery. Furthermore, for the capillary number calculated during MEOR flooding with bioclogging and biosurfactant, lower residual oil saturation was measured than for the corresponding capillary number under abiotic conditions. These results suggest that bioclogging is a potentially effective approach for pore morphology modification and thus flow alteration in porous media that can have a significant effect on oil recovery beyond that predicted by capillary number.
Ceramic Screens, an Innovative Milestone in Sand Control
Authors: Müssig S. , Henriksen P. E , Wildhack S. , Lesniak C.
Published: October 2011

The Danish offshore oil and gas fields in the Danish Underground, operated by Maersk Oil on behalf of the DUC (Danish Underground Consortium), which is a collaboration between A.P. Møller - Mærsk A/S, Shell Olie- og Gasudvinding Danmark B.V. (Holland) and Chevron Denmark Inc., are of mainly tight Cretaceous carbonates with permeabilities of 0.5 - 2.5 mD.

In order to establish economical production rates all the wells need to be stimulated before they can be set on production. DUC is using two types of completions, the CAJ (Controlled Acid Jetting) - liner principle [Hansen, J.H. et al. 2002] and the PSI (Perforate-Stimulate-Isolate) principle [Damgaard, A.P., Bangert, D.S., Murray, D.J., Rubbo, R.P., and Stout, G.W. 1992]. The latter is used when hydraulic fracture operations have been selected for stimulation. Experience showed that during cleanup operations and during the production significant erosion may occur due to backflow of proppant contributing to increased health and safety risks. Operations also faced the problem of sand spreading across the entire facilities and pipelines creating production downtime. In addition resin coated sand having been classified as a "red" chemical in the Danish sector a solution was required to remove its use. Therefore the operator and ESK designed and developed a new sand screen based on ceramic material, which is able to keep the sand out of the production stream and having enough strength to resist the erosional forces. In this paper the development of the ceramic screens is described, and their deployment in two applications is presented: In the first example, the ceramic screen was engineered particularly for preventing proppant flowback in propped fractured reservoirs. For the second application, the ceramic screen was designed as a regular sand screen to stop sand flow from the unconsolidated sand propped fracture.

In addition to the screen development, production results will be discussed for the ceramic screens applied in the PSI completions of two oil production wells in the Valdemar field as well as in a gas production well in the Tyra field.
Geosteering with Sonic in Conventional and Unconventional Reservoirs
Authors: Pitcher Jason , Market Jennifer , Hinz David
Published: October 2011

Azimuthal variations in sonic logs have been observed for many years, both in wireline and LWD data. Rudimentary reactive geosteering methods have been used in the past, including drilling until real-time sonic log detected a change in formation velocity and subsequently altering the wellbore trajectory.

We propose taking sonic geosteering a step further by providing real-time azimuthal images showing the velocities as they vary around the wellbore. Images can also be transmitted at both shallow and deep depths of investigation to determine how close an approaching boundary may be.

While more traditional geosteering measurements, such as resistivity and gamma ray, are highly suitable in many cases, there are instances where the resistivity or gamma ray contrast between beds may be low or the depth of investigation very shallow, making geosteering problematic. However, in such environments, there may well be a porosity contrast, detectable as velocity differences by the sonic tool, which are more suitable to geosteer with. In addition, sonic logs are an ideal way of determining gas contact points in a reservoir, as compressional velocity measurements are highly sensitive to gas.

For unconventional shale reservoirs, sonic anisotropy and its relationship to rock mechanical properties are a principle determinant of a well-placement strategy.

In this paper, we explore some key factors of sonic geosteering, such as depth of investigation, azimuthal resolution, and compressional vs. shear velocity responses. A workflow for integrating azimuthal sonic measurements into existing visualization and geosteering software is described. Field data examples are presented, showing the feasibility of sonic geosteering as well as its current limitations.