bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of a Tight Gas Reservoir with Horizontal Multifractured Wells
Authors: Ehrl E. , Schueler S. K.
Published: December 2007

The concept of multiple fractured horizontal wells has been successfully used for the development of a deep, ultra-tight Rotliegendes gas reservoir. Because of extremely low permeabilities (0.01 – 0.02 md) conventionally fractured vertical wells produced at uneconomically low gas rates. The pilot well Soehlingen Z10 combined the methods of horizontal drilling and multiple fracturing and proved an economic technique for developing the significant gas resources in the tight gas reservoir.

An integrated 3-D geologic model and a field-scale reservoir simulation model were used to optimize future field development. The wells were modelled with a system of local grid refinements (LGR) around the horizontal wells. Adjusting permeabilities and cell sizes of the hydraulic fractures and the surrounding reservoir area helped solve the numerical stability problems without affecting simulation of long-term production performance. The history match for the existing multiple fractured horizontal well, Soehlingen Z10, was based on a five-year production period. Previous analytical studies were confirmed by numerical results. A multi-well program was developed with up to eight wells of 1,000 to 1,500 m long horizontal sections. Each well will be stimulated by 5 to 7 hydraulic fractures depending on the horizontal section length. Timing and sequence of the planned tight gas wells were analyzed using an integrated subsurface-surface study. The development plan incorporates the spare capacity of existing surface facilities and the actual production decline of other producing horizons in the field. Following this study, the Soehlingen Z13 well was drilled, stimulated and brought on production in 1999.
Application of Azimuthal Density while Drilling Images for Dips, Facies and Reservoir Characterization – Niger/Delta Experience
Authors: Akinsanmi O. B. , Aibangbe O. , Kienitz C.
Published: December 2007

The azimuthal density while drilling tool has been successfully utilized in high angle well drilling and evaluation. The evolution of the imaging technology from this tool has opened new avenues in horizontal well evaluation, and the resultant imaging answer product has successfully been used for detailed structural and sedimentological analysis for characterizing reservoirs beyond the resolution of surface seismic.

Conventional well to well correlation techniques have often proven inconclusive in placing laterals in the optimum position within the reservoir. Resulting production from the lateral drain holes has been seen to be greatly influenced by the positioning of the well bore relative to structural and formation dip. Formation dip and structural features have historically been acquired from wire-line logging tools. However, high angle wells present operational difficulties which often result in a decreased use of wireline. Images acquired while drilling by the azimuthal density tool provide a method of resolving the correlation uncertainties, and allow quantification of the structural and sedimentological interpretation and the subsequent production contribution of each zone in the lateral.

The fields where this application was utilized are analyzed. From the data analysis an extra opportunity in terms of reserves has been identified.
Gas shut off using foam: The Solution for unwanted Gas Production?
Authors: Ligthelm D. J. , Eijden G. J. M. van , Gronsveld J.
Published: December 2007

Gas shut off technology for wells with a high gas/oil ratio is extremely valuable to improve oil production and reduce environmental pollution. Foam treatments have been applied to reduce unwanted gas inflow. However, results have not always been favorable. This paper presents a field case supported by a modeling study of successful foam shut-off treatments carried out in the South Chinese Sea. This study shows that the possibility of success of gas-shut-off treatments can be greatly enhanced by having a good understanding of the process parameters. In the Champion field, Brunei, an increasing number of oil wells are shut in due to high gas/oil ratio. In November 1998, three wells were treated with a surfactant/polymer (foam) solution in water, co-injected with nitrogen. In two wells the gas/oil ratio was substantially reduced but also a significant loss in oil productivity was observed, which partly restored in the course of time. The treatments were based on laboratory core flow experiments under reservoir conditions. The experiments served to design the field trials and as input data for simulations with a numerical radial well model, which was used to interpret the field trials. The reduction in gas mobility by a factor between 2 and 10 as observed in the field is consistent with the results of the laboratory experiments.

The study identifies the permeability and temperature window and the type of geological setting and well configuration for which the applied foam system will be successful. This is essential to screen potential candidate wells. It will be shown that in future treatments less damage to the oil productivity and lower costs are possible by omitting nitrogen gas and by reducing the injected volumes.
VLE WAG Injection Laboratory Field in Maracaibo Lake
Authors: Manrique E. , Padrón R. , Surguchev L. , De Mena J. , McKenna K.
Published: December 2007

The VLE WAG pilot in Maracaibo Lake is one of the laboratory IOR fields of the State Venezuelan Oil Company PDVSA. The area of the VLE WAG pilot encompasses 5 production wells, one injection well and one observation well. The producing reservoir C-23 is stratified heterogeneous sandstone. The WAG injection pilot in the VLE field is planned to start in year 2000. The main objective of the WAG pilot is to improve oil recovery from the area being produced since 1991 under natural pressure depletion.

Available data were integrated to have representative description of the reservoir and fluids simulation model. The stochastic description of the C-23 reservoir was used to build the model of the pilot area. Available well data were used to condition the stochastic geological model. Core flood experiments were simulated and interpreted to establish relative permeability data. The available PVT data from different production time periods was reviewed and black oil fluid description was established to account for injection hydrocarbon gas dissolution and oil swelling effects under WAG injection. The established simulation model was used to history match production data and to evaluate WAG injection scenarios. The injection well has dual completion for separate simultaneous water and gas injection cycles. Cyclic simultaneous water and gas injection in the VLE WAG pilot has a potential to improve waterflooding recovery by 5-7% of STOOIP after 5 years of production. The planned tracer injection program will provide additional data for further simulation model adjustments and improvements.

This paper will discuss the integration of data to establish a representative simulation model, history matching and WAG process modelling, VLE WAG laboratory field evaluation.
Predicting the Reservoir Response to Intelligent Wells
Authors: Thompson I. M. , Sarkar R. , Parker E. D.
Published: December 2007

Recent developments in completion design have seen the evolution of the intelligent well. The ability of this well to both measure and control production, and/or injection, within the subsurface is considered a major step forward in field management. It is therefore crucial to be able to model and understand the impact on the field of the technology prior to installation. By modelling the entire system the ideal completion design and field location are evaluated, whilst the reservoir response to the variable choke is predicted for the life of the well. The economic value of the technology can now be understood.

Previous attempts at modelling intelligent wells have crudely adjusted either perforation skin, or near wellbore permeability, to mimic the choking effect. However, the challenge is to firstly, develop a model which correctly predicts the fluid and pressure distribution throughout the completion as well as across the reservoir for each choke orifice, and then to apply the model as a reservoir management tool.

This paper describes a method of executing the challenge by incorporating the surface network and variable choke model of a reservoir simulator within the subsurface. The model simulates the multiphase flow and pressure distribution within the annulus and tubing for any choke orifice. Production is allocated to each choked section and perforation accordingly. Simple adjustments, or the incorporation of new components, within the network, readily permits simulation of the field response to various completion designs.

Performance sensitivity of the model is evaluated in simple homogeneous and heterogeneous environments. Intelligent well models are then developed for two conceptual field developments. In each, field performance is compared with traditional completion designs.
An Integrated Risk Model for Reservoir and Operational Costs with Applications to Total Value Chain Optimization
Authors: Huseby Arne Bang , Brækken Egil
Published: December 2007

The paper presents a new methodology for building integrated risk models for reservoir and operational costs. Although the resulting models are fairly simple, they have proved to be adequate in several real-life applications in large field development projects as a part of a total value chain risk analysis. By using these models it becomes possible to optimize intervention strategies with respect to the total net present value of the project or other success criteria such as break-even price.

When analyzing operational costs related to an oil or gas field, one usually develops a static cost profile based on the assumed expected yearly production throughout the lifetime of the field. However, when reservoir uncertainty is introduced, this approach breaks down, as different production scenarios must be matched with corresponding operational cost profiles. A typical risk analysis involves carrying out some sort of Monte Carlo simulation. To be able to do this, it is necessary to establish a more dynamic link between reservoir and operational costs. While some of these costs are more or less constant independent of the production, others depend heavily on how much the reservoir produces. In this paper we focus on the last category. It is natural to divide such costs into two subcategories: rare events with high costs, e.g., well interventions such as side-track operations, and frequent events with low costs, typically scale squeeze operations. Two different models will be presented dealing with these issues. For the rare events with high costs case, we present a lifetime model where the time is measured in cumulative production. For the frequent events with low costs, the relation between production and operational costs is developed based on curve fitting.
Troll West - Reservoir Monitoring by 4D Seismic
Authors: Elde Rigmor M. , Haaland Annelin N. , Ro* Hans Egil , Ystad Bjørnar , Zachariassen Eli
Published: December 2007

A seismic monitoring pilot survey was acquired in September 1998 for the purpose of qualifying time lapse seismic technology on the Troll West oil field. The main objectives for seismic monitoring on Troll West are to detect areas containing undrained oil and to reduce the uncertainties related with simulated contact movements. The seismic monitoring study has established effective methods for both seismic processing sequences, 4D analysis and history matching, and it has been shown that the seismic monitoring technology is useful on the Troll West oil field.
Avoidance of Formation Damage by Application of Proper Drill-In Fluid (A Case Study of a Mature Field)
Authors: Gaurina-Medjimurec N. , Steiner I. , Simon K. , Matanovic D.
Published: December 2007

Horizontal well – 1H was drilled in a mature field in Croatia with an extended open hole interval and a high differential pressure. As a result, differential sticking has occurred when drilling the horizontal section.

This was the first well to be drilled in that area with application of a drill-in fluid that included specially sized calcium carbonate bridging agent with a blend of viscosifying and filtration control polymers.

To identify the best drill-in fluid composition for the horizontal section, three compositions were evaluated based on fluid-loss control and plugging properties, low-shear rheology (LSRV) and formation damage potential.
Innovative Development Engineering Techinques
Authors: Gayton P W , Miller S D , Napalowski R
Published: December 2007

Triton Development

Increasingly, field developments are characterised by fragmented marginal reserves where development risk cannot be amortised through extended appraisals without compromising project value. It is now important to tailor the system design and phase the capital expenditure to fit with production uncertainties and manage downside risk.

With reference to the Triton development, this paper presents techniques and methods that enable marginal fields to be developed with facility, drilling and reservoir risk fully understood.

The Triton development involves two separately operated fields and three operators – Guillemot West/NW (Veba), Bittern (Shell Expro) - combining in the new build Triton FPSO (Amerada Hess). Rigorous through life production network deliverability reflecting reservoir performance was required to enable identification of central facilities concepts. Co-ordination between the various players was crucial to the success of the project and this was facilitated by the use of integrated reservoir/production system models.

Three techniques are presented in detail:

Operating envelope mapping – using a full integrated production system model (Pipesim) and OLGA in combination to generate performance and behaviour maps to provide decision support to flow assurance design issues.

Pipesim FPT – Field planning tool. A life of field total production network plus reservoir model simulation tool coupled with field development event logic control that allows detailed inflow/outflow derivability, thermal performance and equipment performance to be tracked over field life.

Risk and value engineering – integrated reservoir, facility and economic system modelling coupled to Monte Carlo risk simulation to give life of field NPV and recovery estimates as well as providing risk based decision support.

The paper shows that all of the above techniques can be combined to provide a powerful systematic approach to development engineering.
Blacklick Project Summary, Indiana County, Pennsylvania
Authors: Bajek David T.
Published: December 2007

Coalbed methane has become a viable resource for meeting the needs of natural gas consumption. Many projects were started in 1991 to take advantage of tax credits offered by FERC. These projects have had to carry on beyond the tax credit. One such is Belden & Blake/Devon Resource’s Blacklick Project. The Blacklick Project was started by O’Brien Methane Production as an attempt to cash in on tax credits. O’Brien drilled twenty wells but only six were treated before the project was sold in late 1992 to Devon Resources Inc. and Belden & Blake Corporation partnership. The remaining initial wells were frac’d over the course of the next two years. The overall results were not stellar. Water production exceeded expectations, while gas production had not followed the "typical" incline experienced at other CBM Project areas. In late 1995, Belden & Blake shifted responsibility for the Project from the Corporate Office to the satellite office at Pleasantville. At this time a complete review of the Geology and Operations was under taken. The results of this review spurred a new round of drilling. This drilling utilized the geology to pick optimum areas. The short falls discovered in the operational review were also tested. The 1996 CBM program for Blacklick exceeded the expectations of all involved. The process used to improve this project area required cooperation of Engineers, Geologists and Field Personnel. It also utilized a fair share of practical experience of pumping operations learned in shallow oil production.
Improving the Simulation of Waterflood Performance With the Use of Neural Networks
Authors: Aminian K. , Bilgesu H. I. , Ameri S. , Gil E.
Published: December 2007

Secondary recovery performance of most oil reservoirs is impacted by formation heterogeneity. Therefore, accurate description of the formation attributes is necessary for appraising the economic success of the secondary recovery operations in a complex reservoir. Porosity and permeability distributions are the key formation attributes, which are required for realistic simulation of the secondary recovery performance. The permeability and porosity are usually determined from the analysis of the core samples. Generally, core samples are only available from limited number of wells in the reservoir because of the expenses associated with obtaining and analyzing the core samples. At the same time, geophysical logs are commonly run in most of the wells in the reservoir. Well log data are then utilized to identify the productive intervals and to estimate the formation porosity. A correlation between core-derived permeability and log-derived porosity is often developed and utilized for permeability prediction. However, a reliable correlation between permeability and porosity generally cannot be established in heterogeneous formations. This is mainly due to presence of multiple "Flow Units" within the formation. The Flow Unit is defined according to geological and petrophysical properties that influence the flow of fluids. Prediction of Flow Units is a difficult and complex problem because typically the available information from cores is inadequate. The use of well log data to identify the Flow Units and predict permeability distribution therefore, represent a significant technical as well as economic advantage. In this study, several artificial neural networks were successfully developed to predict the Flow Units, permeability and porosity from the available well log data. The study was performed in an oil filed located in West Virginia. Well log data and core analysis results from seven wells in this field were utilized to train and test the neural networks. The results of the networks’ prediction in conjunction with the relevant secondary recovery data were then utilized to simulate the secondary recovery performance. The simulation results indicated that the neural network predications significantly improved the simulation of the secondary recovery performance.
Parallel Computing Techniques for Large-Scale Reservoir Simulation of Multi-Component and Multiphase Fluid Flow
Authors: Zhang K. , Wu Y. S. , Ding C. , Pruess K. , Elmroth E.
Published: December 2007

Massively parallel computing techniques can overcome limitations of problem size and space resolution for reservoir simulation on single-processor machine. This paper reports on our work to parallelize a widely used numerical simulator, known as TOUGH2, for nonisothermal flows of multi-component, multiphase fluids in three-dimensional porous and fractured media. We have implemented the TOUGH2 package on a Cray T3E-900, a distributed-memory massively parallel computer with 695 processors. For the simulation of large-scale multicomponent, multiphase fluid flow, the requirements for computer memory and computing time are extensive. Because of the limitation of computer memory in each PE (processing element), we distribute not only computing time but also the memory requirement to different PEs. In this study, the METIS software package for partitioning unstructured graph and meshes is adopted for domain partitioning, and the Aztec linear solver package is used for solving linear equation systems. The efficiency of the code is investigated through the modeling of a three-dimensional variably saturated flow problem, which involves more than one million gridblocks. The execution time and speedup are evaluated through comparing the performance of different numbers of processors. The results indicate that the parallel code can significantly improve capacity and efficiency for large-scale simulations.
Reduce the Number of Components for Compositional Reservoir Simulation
Authors: Liu Kai
Published: December 2007

The need to predict reservoir fluid compositional changes under varying pressures and depletion processes arises because the hydrocarbon recovery of some types of reservoirs is strongly composition-dependent. Since hydrocarbon component material balance equations must be solved in compositional reservoir simulation, both computer memory requirements and simulation run time are greatly increased.

This paper presents a series of technologies, including a Fully Automatic Regression Technique, a Best Lumping Scheme, and a Fully Automatic Reservoir Fluid Characterization procedure, to reduce the number of components needed to characterize a reservoir fluid using an Equation of State (EOS). As a result, the compositional reservoir simulation run time can be greatly reduced without reducing the required accuracy of the match with available laboratory data. Applications indicate that a significant speedup has been achieved using fewer components to model the reservoir production processes while the predicted reservoir performance is equivalent to that achieved using many more components.
Thermal Simulation with Multisegment Wells
Authors: Stone T. W. , Bennett J. , Law D. H. -S. , Holmes J. A.
Published: December 2007

The extension of a previously reported well model to compositional and thermal applications is discussed. This multisegment, multi-branching wellbore model has been fully coupled to a commercial reservoir simulator which can operate in black-oil, compositional or thermal modes. In this paper, the discussion will focus on thermal, heavy oil applications where simulation requires a better representation of the wellbore geometry and the physics of fluid flow and heat transfer.
Cupiagua: A Complex Full-Field Fractured Reservoir Study Using Compositional Upscaling
Authors: Ballin P. R. , Clifford P. J. , Christie M. A.
Published: December 2007

The first application of compositional upscaling to the routine modeling of a major reservoir is described. The reservoir, Cupiagua in Colombia, is a rich gas condensate field. Given that Cupiagua falls rapidly below dewpoint, and produced gas is recycled, the main recovery process is the vaporization of liquid components into the gas phase, and transport of these components in the gas phase to production wells. Therefore the process is compositional but flow is dominantly in 1 phase.

Cupiagua is a heterogeneous reservoir, in which the main heterogeneity consists of natural fracture corridors, accounting for more than 80% of the permeability in some areas. It is not possible to represent these features explicitly within the full field model (FFM), nor do they fit a conventional dual porosity representation. Therefore an upscaling process is required.

The process described in this paper is the use of alpha factor compositional upscaling functions, which modify the velocities of individual pseudo-components. Alpha factors are now incorporated into the Cupiagua FFM and are in daily use for all modeling applications in this major field.
Insights into Upscaling Using 3D Streamlines
Authors: Chawathé Adwait , Taggart Ian
Published: December 2007

Large multi-million cell geological models are frequently constructed in an effort to "capture" the vertical heterogeneity measured by well logs and the areal heterogeneity inferred by the depositional environments. These criteria often result in fine scale models at a resolution of 0.1-0.3 m vertically and 30-100 m areally, resulting in reservoir models to the order of 107 grid cells. Recourse is made to upscaling in order to obtain coarsened but computationally efficient flow simulation models. The coarsened models commonly result in no more than 1-5% of the original grid size underscoring the need for judicious upscaling. Of greater importance is to demonstrate, for the chosen grid dimensions, that the upscaled representation is both reasonable and optimal in the sense that a significantly better template would be difficult to obtain.

We consider two non-uniformly coarsened models to demonstrate the issues involved, and show that the use of 3D streamline methods offers insightful alternatives to decoupled analysis for both, the scale-up template design and pre- and post-diagnostics. We confine ourselves to property upscaling methods that use local grid information as opposed to estimating upscaled properties based on some global measure. For this class of problems we demonstrate that the diagnostic phases are necessarily separate from the upgridding and upscaling processes.
Re-Engineering the Well Calibration Procedure for a Large Number of High Productivity Wells
Authors: Siu Alan L. , Al-Khatib Mohammed H.
Published: December 2007

Well calibration after a history match in reservoir simulation ensures that the production wells will give realistic rates during the prediction phase. This process is usually very time consuming. The amount of trial-and-error work increases dramatically as the number of wells and/or the well productivity indices increase. In addition, reservoir simulation models are getting bigger and may contain a greater number of wells as computer hardware expands its limits. A reservoir model with hundreds of high productivity wells would take months to calibrate using conventional approaches. This paper describes a systematic well calibration procedure that yields very high degree of accuracy and requires only a fraction of the usual time. It was demonstrated that, with simple planning in the application of the PFV calibration process, a reservoir model with 500 high productivity wells could be calibrated within a couple days after obtaining a successful history match. The PFV procedure is general and it can be applied to any reservoir simulators.
Coupling Reservoir Simulation Technology with the Internet to Provide Realtime Reservoir Management
Authors: Barden Dick , Smith Chuck , Schubarth Stephen
Published: December 2007

By combining the internet with the latest in reservoir simulation technology, it is now both possible and feasible to direct oil and gas field development in near real-time, using a continuously updated computer model that matches and reflects the actual rate and pressure data observed in the field. While monthly updates are probably sufficient in most cases, operators have the option of updating weekly, daily or even more frequently in order to meet the needs of each situation. This ground breaking approach removes much of the risk from the evaluation of well completions, optimizing the location of offset and infill wells, predicting reservoir pressures, wellhead pressures, flow rates and reservoir drainage patterns, identifying the most effective completion methods, well spacing patterns and many other field management decisions.

This paper discusses how such dynamic reservoir simulation and management can be implemented, even for small, remote production locations. It also cites examples of where this has already been tried, the results that were obtained and describes the experience of those who have actually implemented this approach.

This new methodology, which currently addresses most types of depletion drive and waterflood operations, is of considerable importance to the industry, not only because of the enormous impact it can have on any individual operation, but also because of the paradigm shift that it will bring about as the process gains acknowledgement in the main stream. The capability now exists for operators, regardless of their size or location, to model every new development well (prior to drilling), identify the most cost-efficient reservoir drainage plan and to adjust that plan in an ongoing manner based on actual field/well behavior.
Optimization Methods for History Matching of Complex Reservoirs
Authors: Schulze-Riegert R. W. , Axmann J. K. , Haase O. , Rian D. T. , You Y. -L.
Published: December 2007

Conventional direct optimization methods and Evolutionary Algorithms are applied to the problem of history matching in reservoir engineering. For the optimization of complex reservoir models the potential of parallel computing is investigated. Methods to improve the convergence of Evolutionary Algorithms by introducing expert knowledge is discussed.

An interface program has been developed which links an industry standard reservoir simulator to an optimization software package designed as a multipurpose environment for parallel optimization. Permeabilities, fault transmissibilities as well as relative permeabilites and barrier locations have been included in the optimization.

Results are presented for synthetic and real reservoirs with up to 30 wells and 40 design parameters. The potential and the area of applicability of the optimization method to the problem of reservoir modeling in various modeling phases are discussed. The improvement of performance based on parallelism in a network environment is evaluated.

In conclusion, results suggest that Evolution Strategies can be successfully applied for generating possible solutions in the early modeling phase. The introduction of expert knowledge to the optimization methods is essential for reducing the multidimensional search space and improving convergence.
Calibration of Fractured Reservoirs with Dynamic Data
Authors: Verga F. M. , Giglio G. , Masserano F. , Ruvo L.
Published: December 2007

Fractured reservoirs are reservoirs whose productivity and performance are controlled or strongly affected by the fracture network occurring in the field. Therefore, a correct characterization of the reservoir internal geometry and a suitable description of the effective fracture network are crucial for a predictive model to be reliably applied to performance prediction and production forecast. A new approach has been attempted to validate the reconstructed internal geometry of a selected fractured reservoir by reproducing the dynamic behavior of the reservoir monitored during MDT tests. The description of the reservoir fracture network was achieved by integration of relevant data that could be collected from wireline logs, especially imaging and sonic logs, conventional cores, specifically aimed at microfracture examination, small drilling mud loss analysis, and field scale observations of regional structural heterogeneities from outcrop analogs inspection. Fracture types, distribution, geometry, properties, interaction with matrix, and deformation history were thus defined. Fracture patterns were described in terms of distributions for orientation, size, shape, spatial location and intensity to stochastically generate a static model of the fractured reservoir. The dynamic behavior of the fractured system was reproduced by a finite element flow model able to simulate transient flow through three-dimensional rock masses with discrete fracture networks. Consistency was required between the observed and simulated pressure data also in terms of derivative pressure trend to assure that the reservoir geometry was adequately modeled. Analysis of the model response as a function of the assigned fracture parameters and comparison between the observed and simulated dynamic behavior allowed calibration of the fracture modeling parameters and achievement of a satisfactory description of the reservoir effective fracture network.
Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models
Authors: Sarda S. , Jeannin L. , Bourbiaux B.
Published: December 2007

Advanced characterization methodology and software are now able to provide realistic pictures of fracture networks. However these pictures have to be validated against dynamic data like flowmeter, well test, interference test or production data and calibrated in terms of hydraulic properties. This calibration and validation step is based on the simulation of these dynamic tests. What has to be overcome is the possibility to both accurately represent large and complex fracture networks and simulate matrix-fracture exchanges with a minimum number of grid-blocks. This paper presents an efficient patented solution to tackle this problem. First, a method derived from the well-known dual-porosity concept is presented. The approach consists in developing an optimized explicit representation of the fractured medium and specific treatments of matrix-fracture exchanges and matrix-matrix flows. In this approach, matrix blocks of different volumes and shapes are associated to each fracture cell depending on the local geometry of the surrounding fractures. The matrix block geometry is determined using a rapid image processing algorithm. The great advantage of this approach is to simulate local matrix-fracture exchanges on large fractured medium in a much faster and appropriate way. Indeed, the simulation can be carried out using a much smaller number of cells compared to a fully explicit discretization of both matrix and fracture media. The proposed approach presents other advantages due to its great flexibility. Indeed, it accurately handles the cases where flows are not controlled by fractures alone: either the fracture network may be not hydraulically connected from one well to another, or the matrix may have a high permeability in some places. Finally, well test cases demonstrate the reliability of the method and its range of application.
Reduction of Synthetic Based Fluid Discharges Offshore by the Use of Vertical Basket Centrifuges
Authors: Cannon R. W. , Martin Dale
Published: December 2007

Currently many operators are making a concentrated effort to reduce the amount of synthetic based drilling fluids or muds (SBM) discharged offshore. In order to achieve these goals many new devices are being developed such as the vertical basket centrifuge. Vertical basket centrifuges have been used in the mining industries for years to dry water-wet coal and other processed minerals. These centrifuges have proven successful in the reduction of synthetic based drilling fluid on cuttings (SOC) for drilling operations worldwide (Fig. 1).

This paper will describe the typical cuttings drying equipment suite, layout, and performance of the vertical basket centrifuge. The SBM recovery package involves a two part process: a vertical basket centrifuge for drying of the SBM drill cuttings and the use of a high speed decanting centrifuge for reconditioning and re-use of the recovered SBM drilling fluid.

In most instances the rig's shale shakers are unable to consistently produce dry drill cuttings in relation to the amount of synthetic on cuttings (SOC). Field data has shown as much as 50 to 70 percent reductions in the percent by weight SOC between shale shakers and vertical basket centrifuges samples, thereby effectively reducing the amount of synthetic-based drilling fluid that would have otherwise been discharged overboard.
Engineering Training Needs for the New Millennium
Authors: Wilke J. G. , Hoskins R. C.
Published: December 2007

The roles service company engineers play in the oil and gas industry have changed drastically over the last decade. Prior to 1990, the engineering staff employed by the operating company did most reservoir and production history analysis. The last decade has seen this situation change. During the 90's, while seeking to streamline their own operations, many operating companies began to depend much more heavily upon service company engineers to do the background work described above. Working relationships evolved to the point that service company engineers are often stationed at the operating companies' facilities while performing duties that had previously been the responsibility of the operating companies' reservoir or production engineering departments. This creates an atmosphere of increased service company accountability. Directly proportional to this increase in accountability is the degree of service company engineer responsibility. No longer does the service company engineer simply design treatments based upon the request of the customer.

To meet these demands, service companies have had to implement training programs that equip their engineering staffs with the tools to perform these new job responsibilities, including reservoir, drilling and completions engineering functions. This paper will describe a grid curriculum structure developed to meet the needs of pressure pumping service company engineers. A vast array of classes, some of which were never before available to service company engineers from within, have been viewed as essential to the success of the operating/service company partnerships.

As we move into the next millennium, the curriculum structure must be flexible enough to meet the ever-changing needs of the industry. How will these individuals' roles change over the next decade? No one knows for sure. If the changes are as profound as the last decade, the training program's scope and flexibility are crucial for its future success.
Seismic Determination of Saturation in Fractured Reservoirs
Authors: Brown R. L. , Wiggins M. , Gupta A.
Published: December 2007

The determination of reservoir saturation using the seismic response is an important element of predicting the performance of fractured reservoirs. One of the primary saturation problems the seismic signal can address is the location of the gas cap with respect to the water or oil leg. The classical Gassmann (1951) approach to predicting the effects of saturation upon the seismic signal is not valid for fractured reservoirs. Instead, the results of Brown and Korringa (1975) that account for the anisotropy of the dry rock are used to predict the effects of saturation upon the seismic signals. For a single set of vertical, aligned fractures the P-waves are most sensitive to the saturation when they are nearly perpendicular to the fractures. For S-waves, a classical result is obtained: the S-waves are not sensitive to the saturation within the vertically aligned fractures. However, when the elastic symmetry of the dry rock differs from the case of vertical fractures, the S-waves become sensitive to the saturation. This can happen when either the fractures are tilted slightly away from the vertical or when the fractures are best described as rough surfaces. In these cases, S-waves are most sensitive to the saturation when propagating parallel to the cracks with a polarity perpendicular to the cracks. These results indicate that an S-wave "bright spot" or region of increased S-wave splitting can be used to predict gas versus brine or oil-saturated portions of the reservoir. Since P-waves have the maximum sensitivity to the saturation of a fractured reservoir when they propagate perpendicular to the fractures, they require long-offset surface seismic methods that may be difficult to implement in practice. However, since vertically propagating S-waves with different polarizations can be used

to study the effects of the saturation, they offer the most potential for mapping saturation within fractured reservoirs.
Experimental Study of Near-Critical Behavior of Gas Condensate Systems
Authors: Shen Pingping , Luo Kai , Zheng Xitan , Li Shi , Dai Zhijian , Liu Henian
Published: December 2007

Much special attention has been devoted in this paper to the near critical phenomena of gas condensate systems, including the critical points, bubble and dew point locus, dynamically optical phenomena, and especially the unusual phase transitions in near critical region.

The experimental measurements are carried out during constant composition expansions in high-pressure PVT cell. The percentage-liquid volumes in near critical region are crossplotted to determine the critical points in pressure-temperature diagram. The reddish-brown color is observed in near critical regimes for the fluids due to the complexities of components.

What most fascinated and surprised us is that unusual phase phenomena are unexpectedly observed in the near-critical region. That is to say, during the constant composition expansion process the retrograde dewpoint phase change occurs twice above the critical temperature, and correspondingly retrograde-dew and normal-bubble point phase changes occur sequentially below critical temperature. In two cases, the first-appeared liquid at the bottom of PVT cell first disappears at the same lower-pressure during different temperature CCE processes. These unusual phenomena occur simultaneously for the same fluid at temperature high up to about 100°C. As far as we know, this is the first report of such an observation in the literature.
Improved Techniques For Logging High-Angle Wells
Authors: Bratovich M.W.
Published: December 2007

High-angle wells are becoming coin inon place, particularly in offshore areas. Because of this, it particularly in offshore areas. Because of this, it has become important to increase the deviation angles at which wells can be conventionally logged. Moreover, firm planning factors are needed to decide whether to try gravity-descent or pump-down tools as the first attempt at logging high-angle holes. This paper describes work which contributes significantly to both objectives. New equipment has been introduced to reduce hole friction, increase tool weight and flexibility, and provide a surface indication of push or pull forces at provide a surface indication of push or pull forces at the tool head. These devices have been extensively field-tested in wells with deviations ranging from 45 to in excess of 70 degrees, in the Gulf of Mexico offshore area. Maximum deviations successfully logged by use of the new equipment were somewhat less than the limits predicted by theoretical and laboratory work, but there predicted by theoretical and laboratory work, but there has been a dramatic improvement in success ratios for logging these high-angle wells.
Examination of the Effect of Generically Different Scale Inhibitor Species (PPCA and DETPMP) on the Adherence and Growth of Barium Sulphate Scale on Metal Surfaces
Authors: Graham G. M. , Boak L. S. , Hobden C. M.
Published: December 2007

One of the major concerns within the oil industry is how to deal with scale formation, whether it is in the wellhead equipment, downhole pipelines or the actual field formation. This is because as the scale forms, it begins to deposit itself on the linings of the pipelines, within the equipment and the pores of the formation. The layers continue to build and eventually there is no passage through for the oil. The most effective way to deal with the problem of oilfield scale formation is the use of scale inhibitors, in order to prevent or delay the scale formation. In many scale performance studies, the emphasis is on determining scale inhibitor species that prevent homogeneous nucleation and growth, rather than examining their impact on their ability to prevent heterogeneous nucleation and growth at the metal surfaces such as the production tubulars themselves. The adhesion and growth of scale on metal surfaces is clearly a much more serious problem than precipitation within the bulk solution.

This paper presents results from an extensive series of "adhesion" experiments that examine the effectiveness of generically different scale inhibitor products at preventing barium sulphate adherence and growth at metal surfaces. Tests have been conducted under ambient conditions and under both laminar and turbulent flow conditions.

Results demonstrate that the presence of scale inhibitor, at levels marginally below their concentration required to completely prevent crystal growth, results in increased surface adhesion. Similar results are recorded for the different inhibitor species examined. Furthermore, the level of surface adherence is shown to be more severe under laminar conditions than for tests conducted under turbulent conditions. The indication is that bulk precipitation is being reduced by the presence of the SI which encourages the more thermodynamically favourable heterogeneous nucleation to occur onto surfaces already present. The SI then continues to prevent bulk nucleation and slow growth continues at the surface in order to reduce the system’s overall supersaturation. Increased surface growth relates to the effectiveness of the SI at preventing bulk nucleation.
Barium Sulfate Scale Inhibition in the Deepwater Cold Temperature Environment
Authors: Yuan M.
Published: December 2007

One of the flow assurance challenges facing the deepwater oil and gas field development and production is mineral scale control. In a deepwater production system, barium sulfate scale deposition may arise from two causes, namely: a) commingling of injected seawater with connate formation water, and b) temperature cooling from well bottomhole to wellhead and then in a long subsea flowline. The first phenomenon has already been well understood in the offshore oil industry. However, there is very little knowledge in barium sulfate scaling and inhibition mechanisms in a deepwater subsea system, where the fluid temperature can be cooled to a few degrees Celsius. This lack of knowledge is further hampered by the lack of barium sulfate solubility data at the appropriate temperatures.

In this work, barium sulfate solubilities were measured in BaSO4-NaCl-H2O system at 5°C, in which sodium chloride concentrations ranged from 0 to 5 molal in the solutions. This new solubility data is presented in this paper in comparison with the published solubility data for 25°C and 95°C. Significant reduction in barium sulfate solubility from 25°C to 5°C (and even more from 95°C) was noted, which is more pronounced at higher solution ionic strength (NaCl molality). This paper then presents new results from a series of laboratory experiments that investigate the effect of a wide range of temperatures from 95°C to 5°C on barium sulfate scale precipitation and inhibitor efficacy. The inhibitor effectiveness is studied both dependent and independent of barium sulfate scaling tendency change. Both static jar tests and dynamic scale tube-blocking experiments were carried out. It is found that the apparent reduction or loss of inhibitor effectiveness at colder temperatures in a given brine, as seen in the static tests, is mostly due to increased barium sulfate scaling tendency as temperature decreases, while the inhibitor function may have changed little from one temperature to the other. The other interesting finding is that, although the supersaturation of barium sulfate increases considerably as temperature lowers, the kinetic rate of scale precipitation also slows down at colder temperatures. As a result, barium sulfate supersaturation is not the only driving force for it to precipitate, but temperature plays a role as well. This conflict between thermodynamic and kinetic effects of temperature cooling on barium sulfate scaling results in clearly different results between static scale inhibition tests and dynamic tube-blocking tests. That is, in a given brine, a scale inhibitor apparently performs better or equally at a lower temperature than at higher temperature in a flowing system, while apparently performs worse at lower temperatures in a static solution. Also, as far as barium sulfate inhibition is concerned, the two inhibitor chemistries included in this study did not correspond to temperature change or different test methods in exactly the same manner.