bluuebunny/crossref_metadata_2025 huggingface dataset:
Life Cycle Value/Cost Decision Making
Authors: Harding T. B.
Published: December 2007

Attempts to address life cycle value meaningfully at the planning stage of many complex hydrocarbon investments have failed because we have been over ambitious in trying to tackle the issues in detail. It is proposed that greater success will be achieved by employment of processes which examine the issues initially in less detail, and in terms of risk and uncertainty.
Financial Planning in a National Oil Company: The Mexican Case
Authors: Rivera V. Miguel A.
Published: December 2007

Although financial planning is a business tool widely used by the international business community, its use by Petróleos Mexicanos (PEMEX) hardly began at the end of the previous decade. For almost fifty years the Mexican Oil Company dealt with volumetric targets and within an administration scheme very similar to any federal agency, instead of an international oil company, as it really is. A deep process of structural change started in 1990, aimed to maximize the assets economic value. Within this context, it became necessary to structure a financial planning scheme to monitor the huges investments of the industry, which projects are undertaken in a long term framework and the capital resources applied for those projects have a very important leverage in the Mexican economy. Despite several limitations that the Mexican Government still applies on PEMEX, mainly regarding budgeting and taxation, the Company has been developing a "sui generis" financial model to enable the top management to design mid and long term financial plans, taking into account the predefined strategies, objectives and targets. Considering that PEMEX is placed among the ten most important worldwide oil industries and also the greater flexibility on federal regulations, the Company is obliged to increase its financial planning efficiency in order to achieve the same operation level of other international oil industries.
Production Control Systems Deep Water Installation and Maintenance Features
Authors: Doyle Hickok P. E.
Published: December 2007

The movement of subsea production systems into water depths beyond practical diver working range presents challenges in the ability to install and maintain the equipment. The partitioning of systems into manageable pieces is critical to their successful remote installation and maintenance. Consideration of equipment size and weight with respect to support equipment constraints and ROV capabilities has resulted in a set of equipment that is flexible in its application to deep water requirements. A complete set of support tooling for installation of umbilicals, control pods, electrical and hydraulic distribution modules and their associated interconnections in deep water has been proven.
Second-Contact Water Displacement Oil Recovery Process
Authors: Lepski B. , Bassiouni Z. , Wolcott J.
Published: December 2007

The Double Displacement oil recovery process (DDP) consists of injecting gas into waterflooded oil zones. Upon contact with the injected gas, residual oil globules spread out and form a thin film. Subsequent drainage of the oil film creates a bank which migrates downdip and can be produced. The technical feasibility of DDP has been tested in three fields and is currently being investigated by a joint DOE/Amoco project.1 During laboratory investigation of the DDP at LSU, we observed that a significant amount of oil was displaced when gas-flooded zones were subjected anew to water displacement2. This process was termed Second-Contact Water Displacement (SCWD).

Consolidated cores and unconsolidated sandpacks were flooded at high-pressure and high temperature to simulate different aspects of the process. In addition, experiments using low-pressure transparent cells were performed to gain conceptual insight into the process. Core and sandpack experiments proved that second-contact waterflooding following gas injection could recover up to 20% of oil remaining after the initial water contact.

This process can be used in conjunction with the Double Displacement Process to shorten its duration hence improving its economic potential. The process can also be applied in single-well strong water-drive reservoirs in conjunction with attic-oil recovery.
Development of an Improved Waterflood Optimization Program in the Northeast Savonburg Waterflood
Authors: Schoeling L. G. , Barnett G. B. , Michnick M. J. , Walton A. W. , Green D. W. , Willhite G. P.
Published: December 2007

The Savonburg Field, a shallow reservoir located in southeastern Kansas, has production problems which are common in fluvial dominated deltaic reservoirs and other areas of the country where stripper-well production is important. The problems relate to poor waterflood sweep and lack of an integrated reservoir management program. The poor water-flood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of water injection wells with solids as a result of poor water quality. Reservoir management suffers from the lack of (1) sufficient data collection and organization, (2) integrated analysis of existing data by geological and engineering personnel, and (3) identification of optimum recovery techniques.

A project to increase oil recovery from the Savonburg Field is being conducted under the DOE Class 1 Program. The objective is to improve waterflooding through integrated reservoir management. To date, two technologies have demonstrated positive economics. An air flotation unit has demonstrated that the poor water quality can be improved economically with reduced costs compared to previous operations. Permeability modification treatments plugged channels and increased oil recovery. Earlier treatments yielded five barrels of incremental oil per pound of polymer injected and recent treatments have improved injection profiles. Reservoir characterization studies identified unswept oil in the lower B3 zone and as a result two waterflooding patterns were modified and a new injection well was drilled. Incremental oil is expected to result from this change.
Long Term Use of Oxidizing Agents in Utah Salt Water Disposal Results in Increased Injection Rates and Reduced Operating Costs
Authors: Romaine J. , Vickers Bill , Smith P.
Published: December 2007

The harmful effects of bacteria and sulfidic sludge on the performance of waterflood injection and disposal systems are well known 1–5. Solving this problem by acidizing lines and wells, and manual removal of biomass and sulfidic pads from tanks, is costly in terms of both dollars and time. Treatment with the production chemical chlorine dioxide was seen as a less costly option. Union Pacific Resources Company's, (UPRC), Pine view operation in Utah was the site for the application described. Chlorine dioxide has treated 12,000–13,000 barrels of water per day since 1991 removing and controlling iron sulfide and bacteria in the water injection disposal system. As a result this program has shown documented savings to UPRC of $1.72MM over the last four years.
Effect of the Core Material on Gelation of a HPAM / Chromium System at High Temperature
Authors: Kolnes Jostein , Nilsson Svante
Published: December 2007

The system studied is designed for deep injector treatment, and can also be applied for treatment of a hot producer. Hence, it consists of polymer at a rather low concentration (0.5 weight% polyacrylamide) to ensure high mobility of the gelant. The crosslinker is chromium (oxidation state 3) protected by malonic acid, in order to slow down the gelation process, and to reduce retention.

Large differences in the gelation process are observed depending on whether the gelation occurs in bulk or in a core. Also, large differences are observed between different cores. Here two outcrop sandstones (Berea and Bentheimer), and a North Sea reservoir sandstone have been used. The gelation process shows variations in: gelation time, critical chromium concentration, and changes in pH during gelation. Three important properties of the core material causing this behavior have been identified: 1) content of carbonates (mainly CaMg(CO3)2 and CaCO3) which controls the pH, and thereby the gelation time, the stability of the gel, and precipitation of chromium; 2) content of iron (mainly as FeCO3) - which affects the stability of the polymer; and 3) the amount of clays, which governs the cationic exchange capacity, and thereby the retention.

The gelant behavior in the core material has to a large extent been reproduced in bulk by adding appropriate amounts of kaolinite, and the minerals/chemicals mentioned above, to the bulk solution. It is also shown how to compensate for these changes induced by the core material.

The results from our study show that it is extremely important to know the mineral composition of the reservoir rock before a gel treatment is applied. This knowledge will enable us to avoid breakdown of our gel in regions where we want it to block water, and the prediction of shut-in time in case of a producer treatment is improved. In addition, our findings suggest that for reservoirs where there is a good correlation between low permeability and high clay content of the sand, which often is the case, one might avoid zone isolation when placing the gelant. Even for a relatively high value of vertical to horizontal permeability, a successful gel treatment seems possible with bullhead injection. The treatment can be used both for injectors and producers, and the effect will increase with increasing depth.
Necessity of Dual Injection for Gelant Placement in the High Permeability Layer of a Reservoir with Crossflow
Authors: Shah P. C. , Gao H. W.
Published: December 2007

During the water-flood in a layered reservoir, the high permeability layers will be swept first, leading to a large production of water through such layers. The oil in the adjacent lower permeability layers may be left unmoved unless water shutoff treatment is administered to the thief layers. This work considers a prototype two layer reservoir with crossflow of this nature and investigates the problem of placing a gel plug in the high permeability layer in the vicinity of a producer well for water control treatment. Due to the crossflow, the gelant injected into the high permeability layer may invade the oil zone and shut-off oil production from a part of that layer as well. The depth of the unwanted vertical travel of the gelant into the oil zone is studied through simulation for a variety of reservoir and gelant parameters. The gelant invasion of the oil zone may be reduced or completely eliminated through use of the dual injection method of placement. The situations where dual injection is necessary are identified in this study.

If there is a significant flow channel near the wellbore that allows crossflow between the two layers, the dual injection method is absolutely required for acceptable gelant placement. Gravel pack completed wells also present a very similar problem due to crossflow through the gravel pack. In presence of such a crossflow channel the pressures of the two fluids in dual injection have to be matched very closely to successfully place the gelant in the thief layer.
Acrylamide-copolymer Gel for Profile Modifications: A Case Study in Central Sumatra Basin, Indonesia
Authors: Gandawidjaja Purbaya , Indra H. P.
Published: December 2007

Reservoir heterogeneity is a cause of poor oil recovery in a majority of reservoirs. It provides a path for uneven fluid flow from pressure source to pressure sink. The pressure source can be an injection well or bottom water drive. This paper presents applications of Conformance Technology using Acrylamide copolymer Gel treatments to enhance recovery efficiency. The matrix conformance problems in Sago field, Central Sumatra Basin of Indonesia, have caused water production problems leading to early abandonment and loss of recoverable reserves.

The application of this water shut-off program is expected to automatically shut-off the watered-out high permeability streaks, which in turn will utilize the reservoir pressure increase to be redirected into the lesser permeability streaks still containing bypassed oil, so that better sweep efficiency will be achieved. Adding to the reservoir results of improving both pressure and sweep efficiency, significant decrease of water cut will lower the water production rate, resulting in the decrease of the unit production cost of US$/bbl. The expected increase of oil production rate will give a still better economic value of the project.

Substantial decreases in water production have been realized and in some cases, also increases of the oil production rates as the results of profile modifications achieved through proper treatment applications, strict screening criteria, and extensive laboratory as well as field tests conducted prior to treatments.
Effects of Pressure on Foam Stability; Implications for Foam Screening
Authors: Holt T. , Vassenden F. , Svorstøl I.
Published: December 2007

The stability of foam in porous media has been investigated by core flooding at pressures from 10 to 300 bar, both in the presence and absence of oil. A C16 alpha olefin sulphonate (AOS) and a fluorinated betaine surfactant was studied. In the absence of oil, both surfactants displayed increasing apparent viscosity with increasing pressure. The functional form of the pressure dependence differed for the two surfactants, however. The apparent viscosity increased by a factor of 30 for C16 AOS, and a factor of 3 for the fluorinated surfactant. At 300 bar, the two surfactants performed identically. In the presence of oil (hexane-diluted stock tank oil at low pressure and reservoir oil at high pressure), C16 AOS again displayed increasing foam stability with increasing pressure, while the fluorinated betaine showed the opposite trend.

The data from experiments in oil free cores are discussed in terms of the limiting capillary pressure theory, and measured pressure variation of the surfactant solution surface tension.

The effects of oil on foam stability was assessed by measurement of spreading and entering coefficients at different pressures. For C16 AOS, no change in these coefficients was observed between 20 and 300 bar. For the fluorinated surfactant both coefficients changed significantly, to values indicating detrimental oil-foam interaction at high pressure. Thus, the change in oil-foam interaction seem to explain that the fluorinated surfactant did not show increasing foam stability with pressure in the presence of oil.

The observations show that both the foam stability in absence of oil and the oil-foam interactions varies differently with pressure for different surfactants. This implies that flooding experiments at reservoir pressure are required for a proper screening of foamers.
How To Operate Offshore Production By Remote Control
Authors: Miller Sam K. , Bradham Allen C.
Published: December 2007

Gulf Oil Corporation has installed a unique supervisory control and data telemetering System for three high-pressure gas-condensate wells located in Block 889 near Mustang island, Texas, in the Gulf of Mexico. Automatic instrumentation provides for control functions; measurement of production variables; alarms and monitoring; and platform security.

Production Platform - Block 889, Mustang island Field

This system control point is located on the bay side of Mustang island at the onshore separation and storage facilities. All control functions, signals and process data are transmitted over a single pair of wires through a submarine electric cable between the offshore platform and the onshore control station.

The automatic system has resulted in a net savings of $4,852 per month as compared to manned operations.
Field Test of Foam to Reduce CO2 Cycling
Authors: Henry Richard L. , Fisher D. Ramsey , Pennell Stephen P. , Honnert Michael A.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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.
New Applications for Wellbore Progressing Cavity Pumps
Authors: Mills R.A.R. , Gaymard R.
Published: December 2007

The application of Progressing Cavity Pumps ("PCP's") for artificial lift is still new compared to other technologies. The technology is advancing rapidly and that, combined with new techniques which are learned empirically, continually expands the range of applications. Continuous review is necessary to stay abreast of the technology. This paper discusses the state of the art and the directions in which it is going.

Increasing the range of application of PCP's is mainly dependant upon the advancement of elastomer technology. A review of the elastomers now being used or tested, their application and how they are made, is presented.

Rotor life is often the determining factor in PCP life. PCP suppliers are doing novel work in plating and hardening of rotors. Some of this work is described.

As the displacements of PCP's increased and they were used at greater depths, the increasing torsion on the drive strings created a serious safety hazard and the drivehead designs became increasingly inadequate for the larger loads. The status of the work to create a set of standards which can be incorporated into safety legislation, and upon which petroleum engineers can rely to select driveheads for safety and reliability, is described. This includes the design criteria which must be considered in the selection of a drivehead.

The status of the work on ISO norms is also reviewed.

Two novel applications for wellbore PCP's are revealed. The conclusions and recommendations summarize the applications and limitations of PCP's for artificial lift.

Introduction

The PCP is a type of spiral gear pump. The principle of the PCP was disclosed by Mr. Rene Moineau. Oil well PCP's are very simple pumps consisting of only 2 parts; the stator which is usually attached to the end of the tubing, and the rotor which is usually attached to the end of a sucker rod string. In this case, the pump is powered by rotation of the sucker rod string. The principal and the geometry of the PCP which make it the best sludge pump and particularly suitable for the pumping of deep wells, have been described in previous papers.

PCP's first found wide application in Canada, for pumping sand-laden heavy oil. The capital cost and operating cost advantages led to the application of PCP's for artificial lift of medium crude, usually with high volumes of water. This required the development of high volume pumps with elastomers which resist aromatic solvents and H2S. PCP's with high head rating were first developed for pumping high viscosity crude oils, but can also be used to lift low viscosity crude from deeper wells. This has lead to the requirement for pumps which resist high temperatures and the high aromatic solvent contents of some light oils. Steam flood applications also introduce the requirement for high temperature resistance.

PCP's have also been used extensively in the USA for the dewatering of methane coal-bed wells, although they have been phased out in most fields in favour of small pump jacks as the water production declined.
Thin Gel Treatment of an Oil Producer at the Gullfaks Field: Results and Evaluation
Authors: Rolfsvag T.A. , Jakobsen S.R. , Lund T.A.T. , Stromsvik G.
Published: December 2007

The use of Na-silicate gel in producers is a method to reduce watercut and improve oil recovery by diverting the flow of water in the reservoir. This has been tested twice at the Gullfaks field in the North Sea and the results are encouraging.

This paper focuses on the second treatment at Gullfaks October 1994, where more than 4000 m3 of gelant solution were injected into a partly watered out zone in a producer. The treatment resulted in a reduced watercut and increased oil recovery from the Lower Rannoch formation. Additional oil production of 130,000 Sm3 by the year 2000 is predicted. The added net present value due to this gel treatment is estimated to more than 50 million NOK's at 10% discount rate.

Input parameters used to describe the gelation process and the effect of Na-silicate gel in a numerical simulator are given.
Microscopic Observations of Oil Displacement in Water-Wet and Oil-Wet Systems
Authors: Donaldson Erle C. , Thomas Rex D.
Published: December 2007

Laboratory studies of the behavior of crude oil and brine in a waterflood were conducted using micromodels packed with graded sand. Flow mechanisms and residual oil patterns were observed and photographed through a microscope. The wettability of the micromodels, which possessed many of the over-all characteristics of reservoir rocks, ranged from strongly water wet to strongly oil wet.

Observations of waterflooding showed that each fluid moves through individual networks of interconnected pores during the period of oil production. The size of trapped oil pockets production. The size of trapped oil pockets behind the water front depends upon the wettability of the system. The rapid development and growth of water fingers ahead of the front resulted in early water breakthrough in the oil-wet systems. The length of these fingers ahead of the front depended upon the wettability of the system. When additives were used to stimulate residual oil production, three distinctly different types of residual-oil flow mechanisms were observed. These can be described as slug flow, globular flow, and extraction.

Sandstone cores were used to determine quantitatively the effect of wettability on oil displacement and relative permeability. The results of these tests of different wettability systems are in good agreement with visual observations of the micromodels. Strongly water-wet systems produce more oil and have better displacement efficiency than oil-wet systems.

Introduction

The USBM has long recognized the need for more knowledge about the mechanics of fluid flow within the pore spaces of reservoir rocks. This knowledge is necessary for development of new and improved methods of oil recovery. Waterflooding is the main process used for the secondary recovery of oil, and wettability has long been recognized as an important factor in this process. The importance of the relative wetting tendencies of oils to production and techniques for measuring wettability have been discussed by many researchers.

Micromodels have been used to observe and study fluid-flow behavior during simulated waterfloods. Chatenever described flow mechanisms and residual oil patterns in a model using-glass and/or Lucite beads with water and filtered crude oil. (Reference to specific brands is made for identification only and does not imply endorsement by USBM.) Mattax and Kyte used a network of interconnecting capillary grooves etched into a flat glass plate to observe more closely the behavior of water and refined oil at the interface. Morris and Wieland used a glass bead model with water and a highly refined kerosene to study the effect of varying the wettability. In this research, micromodels packed with clean graded sand were used with centrifuged crude oil and simulated brine.
New Approach to Extended Well Testing in the North Sea Increases Cost Efficiency
Authors: Burris Wesley Jay
Published: December 2007

Economic conditions in the oilfield have identified many areas in which traditional operating procedures are no longer cost effective and must be replaced by alternative methods with more stringent economic parameters. In the UK, this trend has been embodied in the "Cost Reduction in the New Era (CRINE) Initiative."

This paper will present a method used by one service company in the UK to develop an extended well test (EWT) process plant within the CRINE disciplines. By making modifications to existing equipment, the expenditure for new equipment was reduced. This innovative strategy allowed the service company to develop a processing plant that would meet all operational requirements within the operator's cost objectives.

The case history will provide:

The cost to build the extended well test (EWT) processing plant using modified existing equipment compared to the cost of the EWT if new equipment had been used. Methods for modifying existing resources to meet other early production system (EPS) applications. Methods for modifying similar industry pressure vessels for EWT or EPS applications. Information on how long-term labor-cost reductions can be generated.