bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach to Gas Material Balance in Tight Gas Reservoirs
Authors: Engler Thomas W. 
Published: December 2007

Abstract
Gas material balance in conventional, volumetric reservoirs is described by a linear relationship between pressure/z-factor (p/z) and cumulative production. Unfortunately, tight gas reservoirs do not exhibit this type of behavior, but instead develop a nonlinear trend, which is not amenable to conventional analysis. The nonlinearity is a function of two items: the testing method (time) and the reservoir characteristics. For these type of reservoirs the testing time is insufficient to reach average reservoir pressure and from a practical viewpoint, it is not possible to shutin for extended periods of time. Therefore, a method has been developed to use key intersection points and slopes from a tight gas material balance plot to better understand the reservoir behavior.
This work begins by explaining the nature of the nonlinear trend in terms of flow regimes. The primary objective is to improve the estimate of gas-in-place and recovery in a tight gas reservoir. Typically, gas-in-place is underestimated using conventional techniques. It is demonstrated that by using the appropriate slope with the initial pressure an improved (increased) estimate of gas-in-place is achieved. Furthermore, it is possible to distinguish the effect of infill wells and subsequently determine the incremental recovery. Included are field examples from the San Juan Basin and southeast New Mexico, which demonstrate the technique.
Gas Shutoff Evaluation and Implementation, North Slope, Alaska
Authors: Frankenburg A. , Bartel P. , Roberts G. , Hupp D. 
Published: December 2007

Abstract
Oil production on Alaska's North Slope has been limited as a result of gas production and the ensuing gas-handling facility constraints. Diagnosis of gas-production problems is complicated by the fact that many of the wells are high-angle or horizontal. This paper presents case studies in the diagnosis and treatment of excess gas production in three horizontal oil wells located on the North Slope of Alaska.
Candidate wells for gas shut-off (GSO) were identified based on gas flow rates and gas/oil ratio. Wells that were not commercially producible were selected for evaluation as potential GSO wells. These wells were assessed with new-technology logging tools conveyed on coiled tubing or with a downhole tractor. The new production logging technology provided direct gas and oil holdup measurements allowing for interpretation of three-phase production in the horizontal well environments. The goal was to identify dry gas production (i.e., gas production without associated oil production).
After dry gas production was identified, GSO procedures were designed based on the location of the gas entry into the wellbore. Two of the case studies involved GSO from the toe of the horizontal section of the wells, which was accomplished by placing a cast iron bridge plug on coiled tubing above the gas-producing perforations. The third case study identified dry gas production from the top perforated interval. This GSO involved setting a plug below the gas-producing perforations and squeezing them off. The plug was then drilled out using coiled tubing, and pushed to TD.
These techniques proved to be economical gas-shutoff solutions in difficult well environments, and each case resulted in significant reduction of free gas and increase in oil production.
Foamed Cement vs. Conventional Cement for Zonal Isolation—Case Histories
Authors: Kopp Kevin , Reed Shawn , Foreman Jay , Carty Brian , Griffith James 
Published: December 2007

Abstract
Data from six deep gas wells in Wyoming indicate that foamed cement outperforms conventional cement for zonal isolation. Two of the six wells were cemented across the production zones with conventional non-nitrified cements. These wells experienced outer-zone communication after the stimulation treatments. In the other four wells, the foamed-cement sheath provided zonal isolation even after the sheath was perforated and stimulation treatments were performed. The case histories described in this paper provide an opportunity to compare the performance of foamed cement to conventional cement on similar wells within a particular geographic area.
Large-scale laboratory testing has shown that foamed-cement is ductile and can deform as casing is pressurized, but will not crack like non-nitrified cement. These test results were confirmed by the results obtained in the six case-history wells. In the first two wells that were cemented, the operator used the conventional high-strength, non-nitrified cement across the formations. Tracer tags on the stimulation treatment showed that zonal isolation was not achieved and that the stimulation treatment communicated between the high- and low-pressure zones. The operator elected to use foamed cement for the last four wells to help obtain zonal isolation. In these wells, the stimulation treatment remained in the zone, little fracture growth occurred outside the target formation, and communication did not occur between the high- and low-pressure zones.
This paper provides details about the slurry design and job execution on the six case-history wells, and also presents the postjob analysis that verifies the conclusions.
Improved Saturation Determination in Thin-Bed Environments Using 2D Parametric Inversion
Authors: Jammes L. , Faivre O. , Legendre E. , Rothnemer P. , Trouiller J-C. , Galli M-T. , Gonfalini M. , Gossenberg P. 
Published: December 2007

Abstract
The analysis of deep-reading electromagnetic measurements is critical to the evaluation of hydrocarbon reserves. However, in thin bed formations, poor tool vertical resolution and corresponding low sensitivity to hydrocarbon presence make interpretation in the virgin zone difficult. A priori knowledge such as the formation geometry or auxiliary petrophysical information is necessary to overcome these difficulties.
This paper presents a prototype code developed by Schlumberger S-RPC in collaboration with AGIP. Using this code, wireline or LWD, laterolog and induction measurements can be more correctly analyzed in thinly bedded environments (2-D geometry, fluid invaded layers perpendicular to the borehole).
This code has been implemented in a software framework that provides a common environment specifically designed for electrical tool interpretation. Processing modules have a common interface and share common functionalities. Their organization reflects an implicit processing methodology, with progressive refinements that provides the interpreter with a robust and simple to use product, to better quantify reserves.
A preliminary step is to determine the formation geometry, which is carried out by detecting bed boundaries and representing the formation as a vertical sequence of layers. Petrophysical analysis can be invoked to characterize certain formation properties such as shale volume and porosity. These steps are performed prior to resistivity log measurement analysis and serve as a form of a priori knowledge.
Once the formation is described as a sequence of layers, wireline logging or logging while drilling (LWD) tool response can be computed using fast 2D simulators. The estimation of resistivity and the subsequent estimation of saturation will correspond to the minimization of a cost function, defined as the weighted squared difference between the measurement and the simulated response. Confidence outputs can be related to the local shape of the cost function at the end of the processing.
Two important advantages of the new code must be emphasized: (1) the possibility to choose among several petrophysical models to better describe the environment and determine directly parameters such as hydrocarbon saturation, and (2) the possibility to group together beds which are too thin or too close to each other to be analyzed independently, into a so called single optimization interval described by a reduced set of parameters.
This paper presents results obtained on selected benchmarks extracted from real data and compares them with those obtained through more traditional approaches.
Formation Electrical Anisotropy Derived from Induction Log Measurements in a Horizontal Well
Authors: Bang Jon , Solstad Arne , Mjaaland Svein 
Published: December 2007

Abstract
An existing theory describes how electrical anisotropy in the formation affects the response of resistivity logging tools. We have related this theory to the processing of LWD induction logs, and are thus able to calculate the anisotropic resisticities directly from the logs.
The method has been demonstrated by application to logs from a horizontal well section. Anisotropy ratios of 2-5, and occasionally higher values, were obtained for this formation. We also addressed the accuracy of these numbers by using independent sets of input logs. The results indicate that the logs are influenced by factors like invasion in addition to the anisotropy.
Our approach provides a fast and efficient computer algorithm. The output is calculated at the depths of the input logs; hence, the resulting anisotropy becomes a depth-dependent formation property.
Integrated Interpretation of 3D Seismic and Wireline Data to Delineate Thin Oil-Producing Sands in San Jorge Basin, Argentina
Authors: Torres-Verdín Carlos , Chunduru Raghu K. , Mezzatesta Alberto G. 
Published: December 2007

Abstract
Hydrocarbon-bearing sand units in San Jorge Basin, Argentina exhibit thicknesses between 0.5 and 15m, with a mean value of 1.5m. These sand units are associated with ephemereal and laterally heterogeneous fluvial architectures embedded within much thicker shale units of lacustrine and flood-plain origin. Tuffaceous laminations originated from pulses of volcanic activity are also present in the sedimentary column. In view of the wide range of spatial variability and size of porous sands, a typical well is planned to intersect vertically as many sand units as possible. The best producing sands have average porosities of 10% and permeabilities of a few millidarcies. There are several problems faced by the petrophysicist in assessing whether or not a given sand unit should be perforated, namely, (a) discrimination between oil- and water- bearing sands is not trivial because of very low salinity water, (b) there exist substantial vertical variations of effective porosity within an individual sand because of shale laminations, and (c) it is often impossible to assess lateral extent away from the well. We have successfully addressed most of these difficulties using an interpretation procedure centered about the full 2D inversion of wireline array induction data. Full 2D inversion of array induction data is necessary to accurately estimate shallow and deep resistivities, as well as invasion radii in light of significant shoulder bed effects. This procedure has been complemented with the use of borehole NMR data to provide estimates of effective porosity within individual sand units. Finally, we have made use of geostatistical inversion of 3D post-stack seismic data to estimate the lateral extent of hydrocarbon-bearing sands laterally away from the well. We present several application examples that yield results consistent with borehole testing and production data.
The Green Element Method for Numerical Well Test Analysis
Authors: Archer Rosalind A. , Horne Roland N. 
Published: December 2007

Abstract
To use pressure transient test data in computerised methods for integrated reservoir charcterisation numerical simulations of the well tests are typically required. Numerical artifacts occurring in the simulation must be avoided as much as possible so that they do not adversely affect the reservoir characterisation.
This work explores the advantages of a hybrid boundary element method known as the Green element method for modeling pressure transient tests. Boundary element methods are a natural choice for the problem because they are based on Green's functions, which are an established part of well test analysis. The classical boundary element method is limited to single phase flow in homogeneous media. This works presents formulations which give computationally efficient means to handle heterogeneity. The accuracy of the scheme is further enhanced by incorporating singularity programming.
Comparisons of the proposed Green element approach to standard finite difference simulation show that both methods are able to model the pressure change in the well over time. When pressure derivative is considered however the finite difference method produces very poor results which would give misleading interpretations. The Green element method in conjunction with singularity programming reproduces the derivative curve very accurately.
Optimal Uplayering for Scaleup of Multimillion-Cell Geologic Models
Authors: Li D. , Beckner B. 
Published: December 2007

Abstract
Geophysicists, geologists, and reservoir engineers can now routinely build reservoir geologic models with ten million geologic cells and more than one thousand geologic layers. This explosion in reservoir detail capability presents new challenges for existing upscaling methods. Uplayering (the first step of upscaling) is a technique that provides reservoir engineers with optimal geologic layer-grouping schemes for simulation model construction. Much uplayering is still done by hand by reservoir engineers. Even though some advanced methods can provide automatic tools for uplayering, they are limited in the applicable model size and are also computationally expensive. This paper presents a practical and efficient method for uplayering of multimillion-cell geologic models. The proposed method defines a displacing front conductivity, a combination of porosity, permeability, and facies (in terms of relative permeability, endpoint saturation, and various facies rules), as the uplayering property. Use of the new property ensures that the most important geologic features for fluid flow simulation can be preserved after uplayering. The new method utilizes a residual optimization technique to determine the optimal geologic layer-grouping scenario for a given number of simulation layers. The method is so efficient that multiple optimal grouping scenarios, from the one simulation layer model to the model consisting of all geologic layers, can be generated in a short time, allowing the inspection of all possible combinations of layer-grouping scenarios. A residual curve (the difference of the defined property between the fine-layer and coarse-layer models) is produced from exhaustive analysis of all possible layering combinations. Using the residual curve, engineers are able to determine the number of simulation layers needed based on their tolerance of possible loss of fine-layer geologic features. The uplayering method has been successfully employed in most of recent major reservoir study projects in Mobil and results from three of these studies will be included in this paper.
Condensate Banking Dynamics in Gas Condensate Fields: Compositional Changes and Condensate Accumulation around Production Wells
Authors: Wheaton R. J. , Zhang H. R. 
Published: December 2007

Abstract
A bank of condensate can rapidly build up around a producing well when bottom hole flowing pressure falls below dewpoint in a gas condensate field. This bank grows as reservoir pressure declines both impairing well deliverability of gas and causing loss of heavy components at surface. An understanding of the condensate banking processes is essential in predicting the behaviour of the wells and of the fields.
In this paper, a general theoretical treatment of condensate banking dynamics is attempted to show how the compositions of heavy components of a gas condensate change with time around production wells during depletion. A new component relative mobility term is defined and an analytical model is developed for this purpose. The dependence of condensate banking behaviour on the mobility terms and the way it varies with fluid pressure-volume-temperature (PVT)/vapour-liquid-equilibrium (VLE) properties and relative permeabilities is studied in some detail for a range of simple rich and lean gas condensate mixtures.
Results have showed that the newly-defined component mobility term is a critical parameter in the behaviour of condensate banking. Two distinct effects are recognized, one dominant in the near wellbore region and one which is more important in the far field. The compositional change of heavy component is shown to be particularly rapid in low permeability high yield reservoirs and where fluids are close the critical point. Natural steady state situations may not exist with regard to changes in mixture compositions. The reservoir permeability and variation of production rate have significant impacts on condensate accumulation near wellbore and on the way of how the condensate bank develops.
In summary, the aim of this paper is to introduce a new theoretical treatment of condensate bank formation and to use this as a basis to increased conceptual understanding of the processes involved.
Integrated Fractured Reservoir Modeling Using Both Discrete and Continuum Approaches
Authors: Ouenes Ahmed , Hartley Lee J. 
Published: December 2007

Abstract
A new approach that combines the use of continuum and discrete fracture modeling methods has been developed. The approach provides the unique opportunity to constrain the fractured models to all existing geologic, geophysical, and engineering data, and hence derive conditioned discrete fracture models. Such models exhibit greater reality, since the spatial distribution of fractures reflects the underlying drivers that control fracture creation and growth.
The modeling process is initiated by constructing continuous fracture models that are able to capture the underlying complex relationships that may exist between fracture intensity (defined by static measures, such as fracture count, or dynamic measures, such as hydrocarbon production), and many possible geologic drivers (e.g. structure, thickness, lithology, faults, porosity). Artificial intelligence tools are used to correlate the multitude of geologic drivers with the chosen measure of fracture intensity. The resulting continuous fracture intensity models are then passed to a discrete fracture network (DFN) method.
The current practice in DFN modeling is to assume fractures are spatially distributed according to a stationary Poisson process, simple clustering rules, or controlled by a single geologic driver. All these approaches will in general be overly simplistic and lead to unreliable predictions of fracture distribution away from well locations. In contrast, the new approach determines the number of fractures in each grid-block, based on the value of the fracture intensity provided by the continuous model. As a result, the discrete fracture models honor all the geologic conditions reflected in the continuous models and exhibit all the observed fracture features.
The conditioned DFN models are used to build a realistic and detailed model of flow in discrete conduits. There are two main areas where detailed discrete fracture models can be used: (1) Upscaling of fracture properties (permeability, porosity and σ factor) for input into reservoir simulators; and (2) Optimization of well-design, completion and operation based on an understanding of the inter-well scale flows.
For accurate results, the full permeability tensor is calculated for each grid-block based on flow calculations using generalized linear boundary conditions. Inter-well flows are analyzed in terms of the variability in flow paths, characterized by distance and time traveled, through the fracture network connecting injectors and producers.
Improved Reservoir Characterization through Evolutionary Computation
Authors: Romero C. E. , Carter J. N. , Zimmerman R. W. , Gringarten A. C. 
Published: December 2007

Abstract
Computer-aided history matching techniques are increasingly playing a role in the reservoir characterisation process. In general, these techniques provide a single solution that matches the observed data. It has been widely recognised that a solution found to a history matching problem is not unique, but alternative solutions are usually not sought, due to time and cost restrictions.
This paper describes how evolutionary computation can be used to obtain multiple possible solutions without repeating the history matching process. Once a geological and structural model has been defined, Genetic Algorithms are used to carry out hydrocarbon reservoir characterisation by conditioning the reservoir simulation model to production data (history matching). The proposed approach uses ideas from Darwinian evolutionary theory, combining genetic algorithms and geostatistical modelling to generate multiple reservoir descriptions.
The algorithms return a suite of solutions (corresponding to different realisations of the reservoir model) from which the reservoir team can select a representative group for further analysis. The solutions give history matches with a quality comparable to what might be achieved by hand. The method is relatively easy to implement, robust with respect to lost or corrupted solutions, cheap in terms of computational costs, and can be easily parallelised.
Equipment and Operation of Advanced Completions in the M-15 Wytch Farm Multilateral Well
Authors: Algeroy J. , Pollock R. 
Published: December 2007

Abstract
This paper describes the equipment, function, and benefits of the innovative multilateral well completion installed in the Wytch Farm M-15 well operated by BP Amoco. This completion enables production from two different sections of an oil reservoir. Effectively, it is a multilateral well equipped with advanced completion functions much like two wells but without doubling the construction expense. This advanced completion included three hydraulic wireline-retrievable flow-control devices and an electric submersible pump (ESP). In addition, downhole electronic instruments provide monitoring of pressure, temperature, and flow.
Surface controlled, hydraulically operated, downhole actuators are used to effect flow control from each lateral of the well. The actuators have been designed using Surface Controlled Sub Surface Safety Valve (SCSSV) technology. Hydraulic pressure from surface positions the stepwise actuator, which in turn places the choke of the Retrievable Flow Control valve to any of 5 open or a closed position. The flow control valves were individually designed and tested to accommodate the expected flow control requirement from each lateral. The retrievable valves and the mandrels into which they are installed are designed using Side Pocket Mandrel (SPM) technology.
The installation was carried out in February 1999, with production start-up from one lateral following immediately thereafter. The well produced with an expected increased water cut until it was shut-in in September 1999. Through hydraulic cycling of the flow-control valves, the production was changed to the other lateral, producing the same volume of oil, but only a fraction of water.
With the inflow-control valves successfully operating in this well, we further optimized production, including commingled production from both laterals.
This completion set several firsts: one for the long length of its extended reach and another for the first surface-controlled flow device installed below an electric submersible pump (ESP). The team estimated that flow control would allow recovery of an additional 1 million bbl [158 900 m3] of oil that otherwise would not have been economically recoverable.