bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Test of Foam to Reduce CO2 Cycling
Authors: Henry Richard L. , Fisher D. Ramsey , Pennell Stephen P. , Honnert Michael A. 
Published: December 2007

Abstract
A foam treatment was conducted in the Wasson ODC Unit, Yoakum County, Texas, to significantly reduce CO2 cycling through a high permeability zone between injection Well 324 and offset producing Well 455. Three thousand barrels of 0.5 wt% surfactant were injected. A novel placement technique was employed to place the surfactant primarily in the "thief" zone by utilizing crossflow within the wellbore caused by pressure differences between the tighter and more permeable pay zones.
Comparison of the injection and production rates before and after foam generation clearly indicated reduced CO2 cycling between the wells. However, pre- and post-treatment injection profiles indicated that injectivity into all reservoir zones were affected by the foam. This suggested that crossflow within the wellbore was not sufficient in this case to keep surfactant out of the lower permeability layers. This test was run at the end of a water half-cycle. Post-treatment analysis of injection profiles run in Well 324 suggested that better placement of the surfactant may be achieved at the end of the CO2 half-cycle.
The effectiveness of the foam gradually decreased with time, i.e., the injection rate slowly increased, due to drying out of the foam and movement of the surfactant bank away from the wellbore. The foam was twice regenerated by injecting a small slug of water to rehydrate the foam.
Overall the test was a technical success. However, this test was uneconomical due to the low cost of recycling CO2 ($0.10/mcf). In order for foam to be economic at Wasson, better placement of the surfactant is needed so the processing rate in the tighter zones is not adversely affected, and a larger volume (or repeat treatments) is needed to affect areal sweep efficiency.
Improved CO2 Flood Predictions Using 3D Geologic Description and Simulation on the Sundown Slaughter Unit
Authors: Folger L. K. 
Published: December 2007

Abstract
A fully’ compositional simulation model using a detailed three-dimensional geologic characterization was constructed for design optimization of the Sundown Slaughter Unit CO2 flood. The model area comprises 355 acres in the San Andres formation of Slaughter field, located in Hockley County, Texas. Model size and location, three-dimensional geologic description, model construction, and simulation results arc discussed. The three-dimensional geologic description provides a novel approach in defining layers of the simulation model. Six different layering systems were selected from the geologic model to represent actual geology in varying detail. Output from the models showed that the number of layers docs not have a large impact on primary and secondary oil recovery; however, the number of layers significantly affects tertiary oil recovery. The model with the most layers provides the most realistic tertiary oil recovery forecast.
Reasons for a Successful Drilling of the First Horizontal Well in a Highly Productive Reservoir
Authors: Marruffo Ilsis , Achong C. H. 
Published: December 2007

Abstract
This paper shows how the decision to drill the first horizontal well in a highly productive reservoir was made, based on the acceleration of production and cash flow. The reservoir is located in Guafita Norte field, Western Venezuela, contiguous to the Colombian Caño Limón-La Yuca fields. Guafita Norte has remaining oil reserves of 183 million STB, with 26 producing wells on electrical submersible pumps. The reservoir in question presents the following characteristics: an STOIIP of 160 million STB; active water drive; high undersaturation (bubble pressure: 36 psi); a 10 SCF/STB initial GOR; water coning and sanding-up due to fines migration. Rock properties exhibit good quality, with a permeability of 1.5 to 12 darcies and a 25% average porosity. During 1995 the decision was made to drill the first horizontal well in this reservoir based on a 3-D reservoir simulation and extensive economic analyses.
The simulation predicted an initial production rate for the horizontal well scenario 2.5 times greater than the vertical one, and an increase in the incremental cash flow of $4.5 million in 4 years over the vertical well scenario, with ROR exceeding 200%.
The well was drilled with oil mud to avoid hole collapse and was completed open hole with single-screen pack. Its current production ranges between 2000 to 3500 STB/D, clean, under natural flow. The study has clearly shown that the last and decisive parameter to carry out in the decision-making process is the economic analysis, which must be done as extensively as the technical analysis.
The Gypsy Outcrop Model for Testing Geostatistical Methods
Authors: O'Meara Daniel J. , Jiang Renqi 
Published: December 2007

Abstract
Over the past decade, a number of geostatistical methods have emerged for modelling depositional environments. Although these methods enjoy wide acceptance, they have rarely been tested with realistic reservoir models. One reason for this is lack of quantitative data. Another is the lack of consensus on what constitutes a valid test. The present study addresses both of these problems.
Fluvial environments offer a particular challenge for geostatistical modelling. The key to unlocking recovery in such reservoirs lies in a better understanding of how reservoir architecture and connectivity affect sweep efficiency. The present study entails constructing a "deterministic" model of one such reservoir. This model describes six channels within a twenty meter interval of the well-characterized Gypsy sandstone of Northeastern Oklahoma. Detailed spatial distributions of reservoir properties (permeability, porosity, and lithology) have been obtained from extensive sampling and mapping of the geological units of this formation as it is exposed by strike and dip oriented roadcuts. In addition, three-dimensional data has been obtained from a grid of twenty-two boreholes, with oriented core, drilled within three hundred meters behind the primary strike oriented outcrop. This model is as complete and as densely sampled as any model of a producing reservoir is ever likely to be.
Simulations on the Gypsy Outcrop Model show that waterflood recovery efficiencies can be highly variable, depending on the choice of well placement and transmissibility multipliers. Recovery efficiencies are presented for the case of unit mobility ratio displacements. An important focus for comparing various geostatistical methods should be to determine whether they can mimic the variability in recovery efficiencies that is displayed by models such as the present one. The criteria for evaluating the relative merits of competing approaches should emphasize recovery efficiency, rather than mere visualizations of heterogeneities in porosity and permeability.
Just as with reservoir simulation, there needs to be an SPE "Comparative Solution Project" in geostatistics. The Gypsy Outcrop model presented herein can serve as one of several "ground truth" models for evaluating both existing and future geostatistical methods. Comparison of flow modeling results using stochastic realizations constructed from such deterministic models will permit evaluations of the sensitivity of geostatistical methods to the type and amount of data available.
Subsurface Electrical Pump Well Test Analysis
Authors: Coltharp E.D. 
Published: December 2007

Abstract
The subsurface electrical pump, a relatively high volume type of artificial lift, is most applicable in wells that are under the influence of a strong waterdrive or waterflood and have nigh watercuts or low GOR's. The economics of producing these high watercut wells is directly producing these high watercut wells is directly related to the cost of electrical energy used and the operating life of the equipment. To optimize the electrical cost and operation life, one must understand the basic characteristics of the motor, centrifugal pump and cable. This paper covers those basic concepts and presents a paper covers those basic concepts and presents a well test analysis technique and indicates the corrective steps to be taken to accomplish a lower cost per barrel of fluid lifted.

Introduction
In the spring of 1968, Continental Oil Co. initiated a program to determine the causes of poor subsurface electric pump performance. An poor subsurface electric pump performance. An analytical system was developed to evaluate the performance of subsurface electric pumps. The performance of subsurface electric pumps. The results of the analysis indicated the need for company schools at which operating personnel and engineers could become familiar with the proper selection and operation of this equipment. The first 1-week school was held in Nov., 1969. This paper primarily covers the well test analysis, but prior to discussing the well test form, it is necessary to review important aspects of the subsurface electric pump. Each portion of the pump will be discussed with portion of the pump will be discussed with major problem areas stressed.

Subsurface Electric Pump Description
A typical subsurface electric pump arrangement is shown in Fig. 1. The electric motor is on the bottom of the assembly. Above the motor is the thrust bearing and seal assembly, the pump intake, and the multiple-stage centrifugal pump, which is attached to the tubing string. This allows all produced fluids to enter the wellbore below the electric motor and flow around the motor to the pump suction.
The electric motor driving the centrifugal pump is a two-pole, three-phase, squirrel-cage, pump is a two-pole, three-phase, squirrel-cage, induction motor. These motors run at 3,450 rpm on 60-cycle current. Variations in the cycle frequency cause a variation in the motor rpm. This is not a problem when using most purchased electrical power. The design and operating voltage of these motors can be as low as 220 v and as high as 2,300 v. The shaft output of these motors may be from 1/3 up to and including 520 hp. The wellbore fluids must absorb the heat that is generated within the motor. Experimentation has shown that the wellbore fluids must pass the motor at a minimum rate of 1/2 to 3/4 ft/sec in order to cool the motor properly. properly.
Petrophysical Simulation Within an Object-Based Reservoir Model
Authors: Shtuka A. , Samson Ph. , Mallet J.L. 
Published: December 2007

Abstract
The use of "stratigraphic grids" allows the construction of geostatistical models controlled by stratigraphic information. A stratigraphic grid is a 3D grid with boundaries defined by stratigraphic surfaces and cells which respect the stratigraphic organisation (proportional, onlap, toplap,…)
The GOCAD Research Group recently developed object-based stochastic simulations using curvilinear sedimentary bodies and generalized the concept of stratigraphic grids within each simulated object.
We propose a technique for simulating petrophysical parameters within an object-based reservoir model, using this framework provided by stratigraphic grids within each object.
The complete stochastic simulation approach is then defined by the following sequence of operations:
- Define a 3D stratigraphic grid respecting the geometry of the sedimentary limits of the reservoir.
- Next, in the layers where it is required, stochastically simulate the distribution of 3D curvilinear sedimentary bodies (e.g. representing sand bodies).
- Once this object simulation is performed, create a local 3D curvilinear stratigraphic grid contained within each sedimentary body.
- In each of these local 3D curvilinear stratigraphic grids, use geostatistical simulation tools to simulate the distribution of petrophysical properties. The local curvilinear stratigraphic grids so defined honours the sand bodies stratigraphy and allow to generate more realistic simulations than classical global rectilinear grid.
The ultimate goal is to merge all the local 3D curvilinear stratigraphic grids into one global 3D curvilinear reservoir stratigraphic grid filling the whole reservoir. The petrophysical properties of the reservoir can then be transferred from the local stratigraphic grids to the global reservoir stratigraphic grid. Erosion rules between sand bodies can also be accounted for.
With such an approach, based on local stratigraphic grids within sedimentary bodies, we can take into account both the geometry and the topology of the geological bodies.
Use of Seismic to Improve Reservoir Characterisation
Authors: Silva A. Costa , Ramos L. , Guerra R. , Rodrigues J. , Soares A. , Pires E. 
Published: December 2007

Abstract
The use of 3-D seismic has become a key tool in hydrocarbon field appraisal and development planning. So far the emphasis has been put essentially on structural analysis. However, in many cases it is possible to get a better insight on some reservoir petrophysical properties such as lithology (rocktypes) and porosity.
That is the case of mixed carbonate/siliciclastic sequences where deposition is strongly influenced both by sea level fluctuations and structural development. Such process results on large vertical and horizontal heterogeneities which have a great influence on the reservoir fluid flow and oil recovery. Consequently a better understanding of the reservoir internal architecture is crucial to get a more efficient reservoir management. In this paper a methodology for integrating seismic with well log and core data in a stochastic modelling of a reservoir is proposed and discussed. The approach is based on a two conditioning steps: in a first step the spatial distribution of rock types is conditioned to 3D seismic data RMS-Response Phase Map; in a final step the simulated maps are conditioned to "hard" well data.
A case study was selected in order to test a new approach towards the refinement of the current geological model.
Use of Inverted Seismic Data in Well Planning and in 3D Reservoir Modelling
Authors: Johnsen G. , Elde R. , Skalnes A. 
Published: December 2007

Abstract
A major challenge in well planning and in 3D reservoir modelling is to incorporate seismic information. In a North Sea setting, the wells constitute only a few pinpricks in the reservoir, while the seismic data are acquired in 3D over the whole field. Thus seismic data constitutes the only observations available in the interwell areas.
In this paper we give an introduction to seismic inversion and present three North Sea case studies where inverted seismic data have been used. In the first study inverted seismic data was used to predict the thickness of a specific sand layer in the area around a planned well. In the second study seismic inversion has been used as a means for identifying fairly thick stringers of calcite cementation, In the third study inverted seismic data was used to guide 3D geological modelling.
New Products to Solve Scale Problems
Authors: Jewell R.J. , Brogdon B.R. , Lasater Reginald 
Published: December 2007

Abstract
Scale deposits increase production costs, but scale control is inexpensive. Scale deposits do more than plug equipment and flow lines; they can reduce ultimate recovery from a water flood through plugging formation flow channels. While the mechanisms of scale formations and the methods used to remove scale have been covered already, new materials and techniques have shown some improvement in the efficiency of the removal and control of scale deposits. This paper deals with the use of new converters and liquid inhibitors, giving field experience from both the West Texas and Rocky Mountain regions.

Introduction
Scale deposition in producing and injection wells is a problem common to most oil producing areas. Much has been written describing its effect on producing operations and economics.
Previous papers have examined different aspects of scale formation downhole, including compatibility of waters, temperature and pressure effects and the influence of brine pressure effects and the influence of brine concentration. Also, methods to Predict scaling tendencies have been proposed.
Systems to remove scale deposits and inhibit their formation have been developed through the years but new ideas and modern technology are providing improved results. Treatment for removal of gypsum scale is particularly difficult and current work is particularly difficult and current work is being concentrated on this problem.
New techniques being used in the West Texas and the Rocky Mountain regions are improving scale treatment results.
Interactive Well Modelling: Examples of Model Based Trajectory and Completion Design; Single and Multi-lateral Wells
Authors: Alvestad J. , Christoffersen K.R. , Holing K. 
Published: December 2007

Abstract
A new interactive system, NextWell, has been developed for modeling the performance of long, highly deviated or horizontal wells (advanced wells). It is a 3-D, simplified reservoir simulator that computes well inflow and pressure profiles, pressure distribution near wells and in well bores for inclined wells and multi-lateral wells. Its prime areas of use are design of well trajectories and completion, and evaluation of inflow performance including calculation of well indices for full reservoir simulations.
The paper addresses several examples of realistic reservoir model applications in addition to give a short description of the system NextWell. The examples include the study of the performance of several branched well systems compared to more conventional well systems for improving well productivity as well as sweep efficiency. Further an example which illustrate how of NextWell can be used to analyze PLT-data for a horizontal well is given.
3-D Analytical Solution to the Diffusivity Equation for Finite Sources With Application to Horizontal Wells
Authors: Azar-Nejad F. , Tortike W.S. , Ali S.M. Farouq 
Published: December 2007

Abstract
Presenting Discrete Flux Element (DFE) Method this paper provides the solution to the diffusivity equation for horizontal wells with regular and irregular geometries. DFE method is used to derive the equation of potential and its derivative with uniform potential as well as uniform flux Inner Boundary Conditions (IBC). The results showed that the equivalent pressure point moves in time and is not the same as the equivalent derivative point. Pressure derivative with respect to ln(tD) reflects the wellbore length and wellbore distance to the no-flow boundary.
Introduction
Potential distribution around a partially penetrating well, either horizontal or vertical, is to be obtained through solving the diffusivity equation in 3-D. Solution to the diffusivity equation for the sources that are fully penetrated, can be found directly. However in the cases where the sources are partially penetrated and/or they have irregular geometry, direct solution is impractical. This paper presents a new method as Discrete Flux Element (DFE) that permits calculating potential distribution inside the reservoir for partially penetrating wells with irregular geometry. Gravity is not neglected therefore this solution can be used to study special flow problems such as: coning, where gravity plays an important role in modeling the physics of the problem (Azar-Nejad, Tortike and Farouq Ali and Azar-Nejad and Tortike). Therefore the term potential is used throughout the paper. However, if one neglects the gravity effect one can use pressure instead. The reservoir under study is a rectilinear reservoir i.e. an infinite horizontal slab. The other type of boundary conditions can be constructed by the Method of Images. The reservoir is assumed isotropic, however, anisotropy can be introduced through well-known transformation rules. All dimensions are made dimensionless with respect to 2ht, where ht is the reservoir height. Therefore radial flow is represented by a unit slope line in a plot of potential (pressure) against ln(tD).
Dunbar Reservoir Model, A Multidisciplinary Approach to Update Brent Reservoir Description and Modelling
Authors: Baillie J. , Coombes T. , Rae S. 
Published: December 2007

Introduction
The Dunbar Field is situated in the south-central part of the East Shetland Basin, about 135 kms east of the northernmost Shetland islands and 25 kms south of the Alwyn North field (figure 1). The basin, an intermediate terrace region between the East Shetland Platform and the deep North Viking Graben, is characterised by a series of pre-Cretaceous structurally aligned tilted fault-blocks whose relief are clearly seen on the base Cretaceous seismic reflector.
The Dunbar area is 55 km2 (17 km long × 2 to 5 km wide). Dunbar is limited to the north and east by a major NNW SSE fault, down-throwing to the east. Internally, the field is compartmentalised by a number of N - S faults and by a secondary alignment of NE - SW faults which cross-cut and often offset the main N - S faults. The larger-scale faults downthrow to the east and subdivide the field into three main areas, namely the Westflank, the Central Panel and the Frontal Panel. In general, the flanks of the resultant fault-blocks dip gently in a westerly direction.
Sedimentary thicknesses were controlled by major synsedimentary faults. The Brent Group/Upper Massive Sands thickness in the Westflank/Central Panel 'footwall', where perhaps only partial sequences are preserved, is around 90 metres, whereas in the Frontal Panel 'hanging wall' more complete sequences were accommodated with thicknesses in the order of 280 metres.
Hydrocarbon accumulations are present at several stratigraphic levels in the Dunbar area.
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An Integrated Approach to History Matching: A Case Study of the Brent Group in the Eastern Part of the Gullfaks Field
Authors: Aabo A. , Espevold M. , Svinddal S. 
Published: December 2007

Abstract
The Gullfaks Field located in block 34/10 of the Norwegian Sector, is one of the major fields offshore Norway. The field has been in production since 1987. The Gullfaks Field is regarded as a challenge to history match due to its complexity in faulting and communication pattern. In 1993 a project was launched to history match the production from the eastern part of the Brent Group. A joint operator/consultant multi-disciplinary team was established for the task to ensure optimisation and consistency of available data, as well as utilising experience from the field and earlier simulation models. Prior to initialising the model, a thorough data evaluation was performed and a pressure communication model was established. The grid was constructed honouring the geological model, in particular the fault pattern and angles. The simulation model was initialised according to the pre-established communication model, and no major adjustment to the communication pattern was necessary during the history matching. The reservoir energy was history matched as the first step by altering communication across faults, rock compaction and aquifer support. The water production was history matched thereafter, by altering the reservoir transmissibility in well areas, horizontal barriers and relative permeability curves. The history matched simulation model fulfilled the pre-specifications in terms of matching the RFT pressures within +/-5 bars. The water production was matched satisfactorily and water saturation was in accordance with GST and PLT logs. During the history matching process, adjustments in the model were always carefully checked for their physical validity before being implemented in the model. This resulted in a history matched model without artificial, non-physical features. The model is currently in use for production predictions for the Brent Group in the eastern part of the field. Only minor modifications in local transmissibility has been implemented during the one and a half years since this project was finalised.