bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Techniques Yield Savings in Hastings Field Automation
Authors: Deerhake W.F.
Published: December 2007

Amoco Production Company operates approximately 425 wells in the Hastings Field and in early 1969, initiated installation of a supervisory control system for the field. By incorporating a unique approach to net oil and gas measurement and use of existing lease equipment, several hundred thousand dollars were saved. Automation equipment includes a central computer, 11 telemetry units, and approximately 3000 data points at fifty sites consisting of tank batteries, salt water disposal stations, central treaters and ACT unit. Changes in the field equipment included the consolidation of 88 tank batteries into 35 sites. As much of the existing lease equipment was used as possible. Treaters were converted to three phase separators by removing the fireboxes and adding nozzles for alarm switches and controls. Capacitance type BS and W sensors and positive displacement meters were installed in the dump system of each vessel. Two phase separators were modified to three phase vessels for well testing. Central treaters were installed at the field-wide ACT unit to treat the oil to pipeline specifications.

In order to minimize costs and reduce the amount of field electronics, the net oil and gas flow computer logic was built into the telemetry equipment. The capacitance probe on each vessel provides a current signal proportional to water cut, and the positive proportional to water cut, and the positive displacement meter provides 100 pulses per barrel of fluid. The logic in the telemetry determines net oil from these input data and stores the volumes in electronic accumulators. Gas volumes are determined by scanning pressure and differential-pressure transmitters on a fixed time base and computing the extension internally in the telemetering unit.

HISTORY AND AUTOMATION OF HASTINGS FIELD PRIOR TO AUTOMATION PRIOR TO AUTOMATION The Hastings Field Automation Project includes 425 wells on 85 leases covering a 20 square mile area. About half of the wells are flowing and the remaining are on gas lift. The oil is produced from the Frio formation at approximately 6000'. The field has been producing for 35 years and has a remaining life producing for 35 years and has a remaining life in excess of 20 years. Top well allowable in the field is about 150 BOPD subject to market demand. The field is split into two segments, the west having a MER of 60,000 BOPD with a large excess capacity, and the east having a MER of 15,000 BOPD with no excess capacity. Gas is handled by the Hastings Gasoline Plant which recovers NGL and provides the necessary compression facilities. The plant handles about 55 MMCFD.
Simulation of Turbulent Flow in Gas Wells
Authors: Modine A.D. , Field M.B.
Published: December 2007

A method is presented for handling near well-bore gas phase turbulence in complex reservoir systems. The method may be applied in one, two or three phase flow systems. The flow equations describing three-phase flow were modified and incorporated into a single well coning model reservoir simulator. Results are presented for two field gas wells where history matching of observed drawdowns was done to estimate reservoir parameters and turbulence coefficients. The models were then used to investigate water coning behavior in the two gas wells and develop critical rate information.

Introduction

It has long been recognized that to accurately describe gas well performance, in many cases, the effect of turbulence near the well-bore must be accounted for. Katz describes a treatment that may be used to account for the nondarcy flow caused by turbulence in single phase gas flow at steady or quasi-steady state conditions. This and similar methods are widely used and will give reliable results, especially when the parameters needed in the solution are "calibrated" from observed data. However, these analytical solutions are restricted to single phase gas flow and simple reservoir geometry and description.

The analysis of gas well performance in complex reservoir geometries and/or in cases where multiphase flow is occurring is now feasible using reservoir simulation models. The usual approach is to study individual wells using a single-well reservoir simulator or coning model capable of handling one, two or three phase flow with complex reservoir descriptions including stratification, fractures etc. Commonly in the past, the effect of turbulence has not been included in these simulation models because the solution to the Darcy flow problem was difficult enough without further complicating the model. Recent advances in the technology of solving coning problems have now resulted in models that can problems have now resulted in models that can economically be used to study single well performance. Therefore, it is now feasible to performance. Therefore, it is now feasible to go a step further and include the effect of turbulence in these reservoir simulators.

The area where this method probably has the greatest utility is in studying gas-water systems.
A Numerical and Experimental Study of Miscible or Immiscible Fluid Flow in Porous Media with Interphase Mass Transfer
Authors: Corteville J. , Van Quy N. , Simandoux P.
Published: December 2007

A recent paper presented last year described a general multicomponent simulator for two-phase flow. This simulator took into account convection phenomena diffusion and mass transfer between phases; and the main assumptions were:

idothermal one-dimensional flow, two-phase flow (gas or liquid), each phase may be represented by a mixture of three phase may be represented by a mixture of three components or group of components.

This simulator was improved in order to minimize the effects of numerical dispersion.

In order to check the calculations, some experiments were performed under appropriate conditions for precise comparison between experiments and calculations. The fluids used were ternary mixtures of C1, nC4 and nC10, and the experiments were run under high pressure and temperature conditions.

Some examples of numerical calculations are given, as compared with the same experiments on the slug drive case which is the most complex case and also the most widely used in practice. it is shown how the simulator points out the exact time of miscibility breakdown, and then how minimum slug size may be determined in practical cases. practical cases. The calculations made by the simulator are in satisfactory agreement with experience. They help in making a good physical interpretation of the experiments. And the two following conclusions may be drawn:

This project provides better insight into the physical phenomena occuring in miscible displacements. A powerful tool is now available for predicting or interpreting practical cases of predicting or interpreting practical cases of application. These cases concern various types of fluid flow with mass transfer such as (i) high pressure gas drive, (ii) condensing gas drive, (ii) solvent slug process, (iv) carbon dioxide drive, (v) carbonated waterflooding, (vi) and of course totally miscible or immiscible gas drive.
Offshore Platform - Conductor Pipe Interaction
Authors: Yang T.H.
Published: December 2007

Offshore platform-conductor pipe interaction is investigated and the conductors in the role of transmitting horizontal loads into the soil are evaluated for a structure erected in a water depth of 176 feet. It is concluded that the conductor pipes will transmit significant horizontal loads into the foundation media.

Introduction

Offshore structures have an important role in the petroleum industry with the increasing expansion of offshore drilling and production operations. Since the first installation of a platform in the Gulf of Mexico in 1947, a number of questions of basic engineering have been raised and considerable research has been performed in this rapidly developing field.

There have been several papers published in the past 20 years which deal with published in the past 20 years which deal with offshore structural problems in particular and provide valuable contributions. Among those notable are the studies of Howe, Reese and Matlock, Bouwkamp, Cooper, Blumberg and Strader, Freudenthal and Gaither, Karsan and Koehler, and McCleeland et al. It is apparent from the foregoing studies that no specific work was reported on the specific problem under consideration.

Conductor pipes are installed to serve as the outside casing for wells on offshore drilling platforms. Normally, these pipes are driven through the prefabricated conductor guides, which are framed to the platform, after the erection of the jacket on platform, after the erection of the jacket on site, and are considered as parasitic elements to the whole structure. It is then customary that the conductors are not treated as structural members in most cases of structural analyses, although the wave forces, which act on the conductors and are transmitted to the platform via guides, have been taken into account. From experience, however, the conductors, which are typically driven to a penetration of 200 to 300 feet, reveal some characteristics of piles with a potential to transmit some part of the horizontal potential to transmit some part of the horizontal loads into the foundation media, thereby reducing bending moments in the primary piling elements.
Fuel Interchangeability - Measuring Its Extent In U. S. Energy Markets
Authors: Jaworek Gibson W. , Schanz John J.
Published: December 2007

Of increasing importance to the student of fuels economics has been the extent to which different primary energy sources can substitute for each other in the various energy markets of the nation. Knowledge of the nature and extent of fuel interchangeability can aid the fuels economist in projecting trends of energy utilization, as well as giving him a better understanding of the past and present conditions of fuel markets. It is also important to the consumer to know just how much flexibility he can maintain in his energy consuming operations. And, finally, various governmental bodies show keen interest in the degree of energy substitutability in determining public policies concerning the fuels industries. The presence of excess fuel production capacity in the United States during the early 1960's indicates that fuel interchangeability should become more prevalent in the increasingly competitive energy markets of the nation.

Discussion of fuel intercompetition is almost always restricted to qualitative terms because of the lack of comparable statistical data between the different energy sources in geographic or "type-of-use" fuel markets. There are exceptions, of course, such as the excellent fuel assumption data which are available on steam electric generating plants throughout the nation. In other sectors, statistics are at best incomplete. In most instances, indirect fuel consumption indicators, such as sales of fuel burning equipment, are extensively used to measure market shares of a particular fuel; however, these indicators are hard to evaluate precisely without prior knowledge of the total competitive market.

The purpose of this study is to present the results of a comprehensive quantitative study of fuel interchangeability in Pennsylvania in which primary data were obtained from fuel consumers themselves. With such an approach, it was possible to determine, within limits of the sampling procedure, the degree of interchangeability that was theoretically possible for individual types of fuel use. In the final part of this paper, these results are extended to the national level to give an approximation of these measurements of interchangeability for the United States as a whole and to permit a discussion of their importance in future energy trends.
Step Change Improvement and High Rate Learning are Delivered by Targeting Technical Limits on Sub-Sea Wells
Authors: Bond D.F. , Scott P.W. , Page P.E. , Windham T.M.
Published: December 2007

Step Change Improvement and High Rate Learning are Delivered by Targeting Technical Limits on Sub-Sea Wells.

SPE Members

This paper presents an alternative approach to the drilling and sub-sea completion process, the Technical Limit, which has resulted in a "Step Change" in Woodside's performance. Using a simple philosophy characterised by the questions:–Where are we now?–What is possible?–How do we get there?

and applying this tool, three new wells and six subsea completions were completed 20% under budget.

Our target was to drill a directional well in 20 days when the previous best was 42 days. On subsea completions a target of 12 days was set when a conventional approach had previously set 20+ days.

The approach was to ask what would be possible if everything went perfectly with every operation making up the well time. This isn't the usual trouble free time but a well time built up of individual components, with each component performing it's theoretical best performance.

Presented is operational data which confirms that the Technical Limit can be approached. As a result the well construction performance when managed against the Technical Limit delivered step change performance improvement with high rate of learning.

Introduction

Woodside's drilling performance offshore on the North West Shelf of Australia from 1968 to 1992 was erratic. A simple plot of time versus total depth (Figure 1), showed unacceptable scatter and a high average drilling time, particularly when benchmarked against published data (Noerager et al). The authors believed the well construction process was not in control. When faced with an upcoming development project (Wanaea and Cossack developments) we undertook to remedy this.

To get the desired performance an aggressive target setting and planning methodology was developed based on the question "What is possible?" rather than the question "How can we improve?"

Our approach was greatly influenced by achievements in other parts of the world. During the late 70s/early 80s, as documented by Shute et al, Conoco UK Ltd set some drilling operations standards in the North Sea which in our opinion endure today as world class. A major factor claimed in the success of this work came from time analysis which rigorously pursued the identification and removal of drilling problems. The application of this approach was extremely successful. Work by Huber et al also in the North Sea, took a similar approach which, likewise produced excellent results. Latterly Unocal in Thailand have apparently been setting standards in the Far East few can match. Unfortunately, Unocal has published very little on how this high level performance has been achieved. We understand that necessity and aggression drove their improvements.

The high level objective for the Wanaea and Cossack projects the requirement for highly productive wells and low construction cost.

P. 299
Automatic Sampling Act And Commingling Applications
Authors: Lindsey Tom J.
Published: December 2007

Introduction

Subject: This paper evaluates the types of Automatic Sampling Devices and their relation to ACT and Commingling of Crude Oil oproduction application.

Background: There have been varying results in Automatic Sampling on ACT and Commingling operations which are directly related to the application of the Sampling device.

The primary difference in a sampling unit used for an ACT installation and one used on a Commingling installation may be stated simply as the difference in accuracy requirements. The rules and regulations set up by the regulatory bodies are not as strict for Commingling as those for ACT installations, therefore, the precision designed sampler is used for ACT and a more simplified form for Commingling.

The principle of Automatic Sampling is common to both applications and basically the same components are used to construct the complete Sampler Unit. Where there is a difference in the sampling device for each application, it will be noted in the discussion. If a specific reference is not made, it is to be understood that the point of discussion is suitable for either an ACT or Commingling installation.

Description of Equipment:

There are two types of Automatic Sampling Devices and they are as follows:

Type I - The Time-Cycle or Non-Proportional Type.

Type II - The Flow Responsive or Proportional type.

Either type may be applied to both ACT and Commingling installations, but with the increased use of the positive displacement meter Type II - The Flow Responsive or Proportional Type is the most commonly used.

We will discuss briefly the Type I - Time Cycle or Non-Proportional sampler, in order that the difference between the two types may be more clearly indicated. First, though, let us look at the definition of the word "Automatic" and the word "Sampling".

By definition, the word "Automatic" means self-acting, especially of mechanical devices. The definition of the word "Sampling" is a small part of anything selected as a sample for inspection or analysis. Therefore, by combining the two definitions, we have a selfacting, mechanical device selecting a small part of anything for inspection or analysis. The actuation of the mechanical device may be accomplished by pneumatic, electric or hydraulic transmission.

The Type I sampler may be a continuous sampler where one or more equal increments of sample per minute is taken at a uniform rate, or an intermittent sampler where less than one equal increment per minute is taken. The continuous or intermittent sampler may be paced or actuated by an electric time clock, either a pneumatic or hydraulic transmitter, if the pulse is transmitted on a definite time interval. The most commonly used transmitter is the electric time clock when electric power is available. This type of sampler is most applicable where custody transfer is made by manual means, such as hand gauging a tank, but Automatic Sampling is desired.

The Time Cycle or Non-Proportional type of sampler is recommended only where the rate of flow is reasonably constant during the entire sampling period.
Near Wellbore Permeability and Damage Measurements: Experiments and Numerical Simulations for Interpretation of WFT Data
Authors: Samaha A. , Huang K. , Kasap E. , Shwe T. , Georgi D.
Published: December 2007

Wireline Formation Test (WFT) can provide a valuable, cost effective source of near wellbore formation damage data. Interpretation of WFT data can be improved with numerical simulation and laboratory experimental data.

A 3-D numerical simulator for WFT was developed and a comprehensive study of problems associated with the wireline test was made. The simulator results are interpreted with the concept of geometric factor. Case studies include sensitivity to formation damage, internal probe diameter, fluid compressibility and viscosity, formation permeability, and drawdown tank volume.

The radial grid system used in finite element method is particularly amenable to handling practical problems with real WFT flow geometries and configurations. The simulated test pressures match well with actual field data.

In addition to the numerical simulations, an experimental setup which models measurements on a downhole damaged formation was built and attached to a laboratory probe permeameter equipment. This experiment enabled us determine dependence of the measured permeability of the damaged formations on the severity and the depth of damage. The results of the experiments are also in good agreement with the 3-D numerical simulator results.
Review of Reservoir Engineering Aspects of Conformance Control Technology
Authors: Azari Mehdi , Soliman Mohamed
Published: December 2007

Conformance control is any action taken to improve the injection or production profile of a well. It encompasses procedures that enhance recovery efficiency, improve wellbore/casing integrity, and satisfy environmental regulations. Unwanted fluid production in oil- and gas-producing wells is a limiting factor that controls the productive life of a well. The cost of produced water disposal in an environmentally non-threatening fashion may be a major concern for many producers. In addition, control of excess water and gas production improves profitability by allowing additional oil to be produced.

Application of water control technology assists to minimize water production and maintain the oil flow rate of a well. Reservoir engineering and well testing play essential roles in characterizing and detecting the problems associated with producing formations and wells.

This paper starts with problem identification in both producing and injection wells. It then covers the behavior and control of several types of reservoirs with different drive mechanisms. Applications of reservoir simulation and well testing in the control of water and gas coning, determination of the amount and the best appropriate treatment application, effect of formation layering, control of relative permeability to water, application of permeability blocking agents, water channeling, secondary recovery, viscous fingering, and polymer flooding are detailed in this paper. In addition several techniques to evaluate the overall success of a conformance control procedure are presented.
Supercharge Pressure Compensation with New Wireline Formation Testing Method
Authors: Proett Mark A. , Chin Wilson C.
Published: December 2007

Wireline formation testers are increasingly being used to obtain formation pressure and permeability measurements which in turn are used in geological evaluations and in designing well completions. It is generally assumed that the pressure measured by the tester probe is near formation pressure. Unfortunately, in many instances such as in low permeability formations, the mudcake is not adequate to isolate the hydrostatic pressure from the formation near the wellbore. As a result, the sandface pressure measured with the formation tester is "supercharged" and not the formation pressure after all. This sandface pressure may be as much as l.000 psi over the actual formation pressure of interest. This paper demonstrates that a new analytical model can be used along with a new testing technique to correct the measured pressure to actual formation pressure.
Maintenance Experience With LACT
Authors: Bailey Jim
Published: December 2007

With the rapid growth of LACT equipment used in the sale of crude oil, the volume of maintenance required of this equipment is increasing somewhat proportionally; for this reason, the object of this paper is to stress the importance of careful consideration with regard to maintenance when initiating LACT unit installations. Also to advance methods by which LACT unit maintenance costs can be minimized, both when specifying unit components at time of purchase, and during the operation of the unit. The decrease in production costs normally realized from LACT unit installations can be reduced still further with the employment of these maintenance methods.

Introduction

As the large majority of LACT units being installed are of the positive displacement type this paper excludes the maintenance of volumetric type LACT equipment.

The realization that a large part of the LACT field maintenance costs could have been eliminated had the production personnel buying and operating the units been more experienced with this type of equipment prompted the writing of this paper.

The following proposals are an effort to convey the experience of designing, manufacturing and maintaining many units for many users.

The design of a LACT unit from the maintenance standpoint only, presents the problem of increased initial cost. Therefore, the economic study used for the justification of the unit purchase can also be used to dictate the extent to which unit components can be specified with maintenance minimizing in mind. As the majority of all components incorporated in these units are well known, no illustrations of individual components are included. Figure no. 1 illustrates the general location of components that might be included in a P. D. type LACT unit.

Unit simplicity should be one criterion used to dictate component specification, as the more complicated a unit the more maintenance is required of other than the operating production personnel. Each component added to a unit for any purpose furthers the possibility of component malfunction. Therefore, if acceptable, a unit containing a minimum of components is the most desirable from the maintenance standpoint.

COMPONENT SELECTION

There are numerous manufacturers of LACT components, the majority of which offer very high quality components that will represent a minimum of maintenance. For this reason no attempt is made to recommend any manufacturer's products, but merely to purpose the use of certain types of equipment that have proved to be more desirable for LACT use than others.
Reserves and Performance of Canyon Sand Gas Wells, 1970-1994
Authors: Swindell Gary S.
Published: December 2007

Two fields, Ozona (Canyon) and Sawyer (Canyon), with more than 4,000 total wells, contain the majority of wells in the Canyon Sand trend of Crockett, Edwards, Schleicher and Sutton Counties in Southwest Texas. Average ultimate recovery for the fields decreased from 1,100 MMCF/well for wells drilled in 1970 to 400 MMCF/well for wells drilled in 1985, then remarkably reversed the trend. Recently drilled wells (since 1991) are expected to recover an average 625 MMCF. Initial monthly production decreased from 15,000 mcf/month to 5,000 mcf/month in 1985 and then increased to the present 12,000 mcf/month. Average first year wellhead pressure continued to decrease throughout the 25 years studied to a present 1300 psig in Ozona and 700 psig in Sawyer. The data suggest that drainage interference began to be a factor in about 1985 in the more densely developed areas. Although the average well density was about 200 acres per well in 1985, the true density in areas of active infill drilling probably approached 120 acres per well. Present average density is 143 acres per well in Ozona Field and 131 acres per well in Sawyer Field, but many leases are developed on density of 80 acres or less.
Interactions of the Horizontal Wellbore Hydraulics and Formation Damage
Authors: Civan Faruk
Published: December 2007

A model for prediction of the formation damage by rock, fluid, and panicle interactions in the porous formation around hydraulically fractured horizontal wellbores considering the effect of the wellbore hydraulics and filtercake is presented. The processes governing the various formation damage mechanisms and the filtercake are represented by the models developed by Civan et al. The wellbore hydraulics model by Sharma. et al is incorporated into the model to take into account for the effect of the wellbore fluid pressure variation on formation damage. The fluid hydraulics in the fractures are represented by extending and modifying the approach by Barree and Conway. For simplification purposes, the two-phase flow through porous media is described by facilitating a unit end-point mobility ratio formulation following Craig, Collins, and Dake. The well, fracture, and reservoir hydraulics are coupled by imposing the well and fracture pressure equations as the boundary conditions for the reservoir by extending the approach by Soliman for the three dimensional case. This model is applied for mud invasion into the near wellbore formation from a hydraulically fractured horizontal well.
Determination of Dispersion and Diffusion of Miscible Liquids in Porous Media by a Frequency Response Method
Authors: Goss Michael J.
Published: December 2007

A new method of measuring molecular diffusion and axial dispersion during miscible displacement in porous media is described. Equal density and viscosity liquids are injected into the porous medium at a constant volumetric rate with a sinusoidal concentration of fixed frequency and amplitude at the inlet. Amplitude attenuation and phase changes are measured in situ along the direction of flow; dispersion is calculated from these frequency response measurements. Molecular diffusion is determined by stopping the flow and recording the transient decay of the concentration sin waves.

Measurements were made in a consolidated sandstone core using mixtures of isopropyl alcohol and deobase. The in-situ concentrations were determined at various positions along the core from changes in dielectric constant. Dispersion coefficients calculated from the standard dispersion equation were found to depend on wavelength, contrary to the basic postulate that the dispersion is frequency postulate that the dispersion is frequency independent. This indicates that the standard dispersion equation is inadequate since, at a given injection rate, the dispersion coefficient will depend upon slug size.

The capacitance model requires data obtained at three different wavelengths for each determination of the dispersion coefficient. mass transfer coefficient, and stagnant volume fraction. Thus, the effect of wavelength on these parameters is not well defined. Experiments using additional wavelengths indicate that the parameters are still frequency dependent, but the variations are smaller and less systematic than those obtained with the standard dispersion model. The dispersion coefficients obtained from the capacitance model are lower than those obtained from the standard dispersion equation.

The main features of the sinusoidal method are that it is a steady-state analysis which may be applied to many models. The time required for the measurements is short relative to the transient methods, and it provides a method of measuring the molecular diffusion in addition to the dispersion from the same experiment.

Introduction

The potential importance of enhanced oil recovery by miscible displacement processes is demonstrated by the large number of studies of diffusion and dispersion of miscible fluids in porous media reported in the literature of the porous media reported in the literature of the last decade. These investigations have almost exclusively employed an assumed step change input followed by analysis of the average concentration distribution at the system outlet as a function of time (breakthrough curves).
Proppant Flowback Control in the Burgos Basin
Authors: Prado-Velarde E. , Sánchez-Bujanos J. M. , Valenzuela A. , Fragachán F.
Published: December 2007

Proppant flowback following a hydraulic fracture treatment, is a major problem in the Northern Mexico area. Frequently, Proppant flows back as the well returns to production. Generating huge amount of cost associated with wellbore cleanouts and damage to surface facilities. In addition, production is delayed due to long shut-in times and the need to initially produce the well under choke.

Therefore, been able to control proppant flowback at fracture closure would not only eliminate the extra expenses associated with it, but would allow to return the well back to production inmediately with optimized chokes. In other words, an optimized proppant free robusted production.

This paper presents successful applications of stabilizing proppant packs with randomly oriented fibers of similar density to the proppant in dry gas reservoirs with low permeabilities (<0.5 md). All wells were put on production immediately following fracture treatment, with an average of almost 2 fold production increase over resin-coated proppant treatments, having a case with up to 12 folds of increase. During "clean-up" of the wells, return fluids were collected for evaluation confirming expected proppant control and fluid compatibility between fracturing gels and breakers. Finally, production performance months after the treatments are discussed including conclusions and recommendations derived from treatments.
Improved Offshore Drilling in the Cretaceous (With Flint) and Jurassic Rock – Mexico
Authors: Ortiz Blas , Martinez Humberto Castro , Garcia Leonardo Martinez , Salinas Juan Gaspar
Published: December 2007

The introduction of a new Polycrystalline Diamond Compact (PDC) product into Mexico's oil market has been shown to help improve drilling time through the Cretaceous (with flint) and Jurassic rock. Through teamwork of various parties involved, the objective of efficiently drilling this difficult formation was accomplished.

This paper discusses specific design features which improved bit selection for this application. Examples of design considerations include bit profile, cutter size and type, cutter density, hydraulic configuration and blade count.

A presentation is given of performance data, operational details and economic analysis concerning use of bit design ultimately selected. This data indicates that an increase in overall drilling performance contributed to the success of economically drilling the Cretaceous (with flint) and Jurassic rock.
Microbial Methods for Improved Conformance Control in Porous Media
Authors: Stepp Anita K. , Bryant Rebecca S. , Llave Feliciano M. , Evans Deanna B. , Bailey Scott A.
Published: December 2007

Water handling is a major expense involved in producing mature oil fields. Reservoir heterogeneities and variations in permeability can aggravate the problem of water production and significantly reduce the efficiency of oil production. Several methods for improving reservoir sweep through conformance control have been used. Methods such as crosslinked polymer technology have alleviated problems associated with reservoir heterogeneity. Other alternatives such as microbial- and surfactant-based methods have been proposed. This paper presents the results of research conducted on polymer-producing bacteria that were isolated and tested at various temperatures and salinities. Coreflooding experiments were conducted to show the effectiveness of microbial treatments. Reduction in effective permeabilities by as much as 90% were achieved due to in situ polymer production. Noninvasive imaging techniques such as magnetic resonance imaging (MRI) and computer-aided tomography (CT) were employed to visualize changes in fluid distribution in porous media. High permeability areas were blocked by biopolymer production, resulting in brine diversion into lower permeability areas.
Hot Water Flooding for High Permeability Viscous Oil Fields
Authors: Goodyear S. G. , Reynolds C. B. , Townsley P. H. , Woods C. L.
Published: December 2007

A number of North Sea reservoirs contain viscous oils in high permeability sands. One possible IOR technique is the injection of hot water using long horizontal wells. A sector model for a high permeability reservoir containing a 400 cp oil underlain by a large aquifer has been constructed. Hot water injection was compared to cold water injection. Hot water flooding can recover significant volumes of incremental oil and extend the economic life of the field. The incremental recovery mechanism is a complex interaction between gravity forces and temperature induced changes in viscosity and density. Improved sweep in some regions is partly offset by oil resaturation of previously swept regions. Thermal expansion of water plays an important role, the lower density of hot water reduces thermal loses to the aquifer and speeds up the propagation of the temperature front through the reservoir.

A risk management study is reported in which sensitivities to well bore friction, kv:kh ratio, heterogeneity and relative permeability are investigated. The optimal choice of the injection well position (different depths in the oil column from the top of the reservoir) is considered for cold and hot water flooding and is shown to be strongly determined by the kv:kh ratio. Significant friction in the horizontal producers and injectors can be detrimental to hot water flooding performance. A Monte Carlo analysis is performed to select the most appropriate well position. This also shows, for a reservoir of this type, that hot water has the potential to add value to a development scheme at acceptable levels of project risk.
Field Scale Simulation Study of In-Situ Combustion in High Pressure Light Oil Reservoirs
Authors: Tingas John , Greaves Malcolm , Young T. J.
Published: December 2007

Air injection may be an efficient EOR process for deep high-pressure light petroleum reservoirs, for example those found in the North Sea area. Based on phase behaviour analysis by a pseudo-compositional approach and combustion tube simulations, comparative reservoir simulation studies have been conducted to evaluate the potential and displacement characteristics of processes in high-pressure, volatile light petroleum reservoirs.

The primary objective of the study is to examine the feasibility of in-situ combustion processes in North Sea type high-pressure, volatile light oil reservoirs. The reservoir operational parameters have been optimized, and the results of this study are useful for screening of EOR processes, as well as the design and interpretation of in-situ combustion projects.

A simulation study has examined the sensitivities of important in-situ combustion parameters on a field scale. Variations in well pattern size, air injection rates and injection fluid (air, O2, CO2, N2 ) were also examined. Techniques were devised to model the combustion process in a large field-size grid. Results from areal and cross-sectional models were combined to obtain a three-dimensional analysis of the fire flood performance for various well patterns.

Simulation runs revealed combustion front extinction problems due to large grid block size expected for well spacing higher than 2.5 acres also with kinetic controlled field scale models. Extinction of the combustion front significantly reduces predicted areal sweep and oil recovery, resulting in shorter project lifetimes. Kinetic controlled field scale models for well spacing lower than 2.5 acres can predict combustion front formation and vaporization of water and light petroleum components, when simulated with commercial simulators having about 200 grid blocks.

The simulations also show that the vertical sweep efficiency is predominately controlled by the vertical permeability variation in the reservoir. The detailed simulation output showed that mass transfer between phases, oil vaporization, cross flow between layers and heat loss to the adjacent formations are important processes in this thermal recovery process.

Front tracking and a thin flame technique are considered to be important for enhancing simulation capability. The development of more advanced non-isothermal simulators with these capabilities will increase the reliability of air-flood simulation predictions in high pressure light petroleum reservoirs necessary to reveal higher recovery potential than predicted by current simulation predictions.

The Improved Oil Recovery (IOR) potential performance of thermal IOR processes, such as air and oxygen injection in-situ combustion processes, is predicted the highest among the alternative options.
Foam Displacement Modeling in CO2 Flooding Processes
Authors: Chang Shih-Hsien , Grigg Reid ?.
Published: December 2007

A foam model based on the foam resistance factor has been developed and has been incorporated into two reservoir simulators. The first is a pseudo-miscible simulator, MASTER, obtained from the Department of Energy, and the second is an equation-of-state, compositional simulator, UTCOMP, obtained from the University of Texas at Austin. Both simulators have been successfully modified to simulate foam flooding processes where the resistance factor data are input as lookup tables. In the validation exercise, an injection schedule that mimics an actual foam field pilot test was used. The simulation results show an increase in the oil production rate, attributed to the effects of foam, and are consistent with the observation from the foam field pilot. The results also show successful profile modification because of the presence of foam, thus resulting in significant sweep improvement. Agreement between MASTER and UTCOMP was good.
Composition of Remaining Oil in a Mature Steamflood
Authors: Richardson W. C. , Deemer A. R. , Nelson C. E.
Published: December 2007

Detailed compositional distributions of remaining oil from cores in Kern River Field steam floods have been characterized to evaluate the effect of steam distillation/condensation on the low Sor (6%) observed in the steam zone, and to bear on the mechanisms of the steamflood process in general. Steam distillation of heavy oils in the 10–14 ° API range has traditionally been thought to have little impact on oil recovery.

Oil compositional analyses have been performed on many recent (1992–94) core samples from temperature observation (TO) wells in Kern River steam floods. Samples were chosen to reflect a range of initial and historical conditions observed in the steamflood at Kern River.

It has been found that the oil composition in the steam zone is depleted and oil near the vapor/liquid interface is enhanced in light to intermediate hydrocarbons relative to the composition of base oil samples. The data show that steam distillation is significant in the steam zone where low Sor (6%) is achieved. The implications of the effect of steam distillation/condensation on the steam flood process based on this data will be discussed.
Development of Dual-Permeability Thermal Simulator and Validation for Yates Field
Authors: Winterfeld Philip H.
Published: December 2007

Conservation equations for single-porosity and dual-permeability transport are similar except for matrix-fracture transport terms. A dual-permeability thermal simulator is developed starting from a single-porosity one by replicating the single-porosity grid, denoting one half of the grid to be fractures, the other half matrix, and introducing connections between analogous gridcells of the two halves that account for matrix-fracture transport. Consequences of replicating the single-porosity grid, which doubles the number of gridcells, are discussed. The dual-permeability simulator was developed to simulate steam injection in the Yates field. A two-dimensional and three-dimensional example of steam injection into a reservoir are shown. The two-dimensional example is used to validate the dual-permeability simulator by comparing results to a single-porosity simulation in which fractures are represented explicitly as narrow slits.
Reservoir Characterization Methodology to Identify Reserve Growth Potential
Authors: Holtz M. H. , Hamilton Douglas S.
Published: December 2007

The information available for characterizing a reservoir is insufficient to develop a unique model. However, by applying the proper reservoir characterization methodology, a model can be constructed that optimizes and integrates all the data and thus facilitates the identification of reserve growth potential. This methodology contains four steps: (1) determining reservoir architecture, (2) establishing fluid-flow trends, (3) integrating reservoir architecture and fluid-flow trends, and (4) identifying reserve growth potential. The key to determining reservoir architecture is the application of generic sequence stratigraphy. The reservoir architecture is determined by ascertaining the internal reservoir stratigraphy, defining the stratigraphic unit geometries, interpreting the distribution of depositional environments, and combining stratigraphy with structural character. Establishing fluid-flow trends should be accomplished within the context of the stratigraphy. This step includes determining the initial fluid properties, generating a production-time-series analysis, analyzing any variation in fluid chemistry, assessing well test data, and determining the direction of injected fluids. The third and pivotal step of integrating reservoir architecture and fluid-flow trends has four steps. It begins with designing geologically based petrophysical models, then concurrently identifying the correspondence between reservoir architecture and fluid-flow trends and establishing reservoir flow units. Next, the petrophysical properties are distributed spatially and the hydrocarbons in place are calculated. The final step is identifying reserve growth potential. It is accomplished by calculating reserves, delineating the remaining hydrocarbon resource, generating reserve growth concepts, and targeting reserve growth opportunities.
Application of Systems Analysis Can Increase Production by 200 Percent in High Volume Gas Lift Wells
Authors: Jones Doyle L. , Brown Kermit
Published: December 2007

Total fluid production and hence oil production can be increased significantly by production can be increased significantly by evaluating and modifying presently installed gas lift system. Many gas lift systems were improperly designed initially, and as a system was expanded, the inefficiencies were compounded. The more critical design features of a continuous gas lift system are tubing sizes, operating gas lift pressure, proper valve design, and surface back pressure. The optimization of any one of these features will improve a system, but the proper design of all four will result in the most efficient system.

This paper will show how production from a 6,000 ft, well was increased from 620 bbl/D to 2,280 bbl/D by optimizing the gas lift system. The effects of changing the tubing to a larger size are graphically illustrated. Streamlining of wellheads, flow lines and separator headers are shown to be a necessity in reducing excessive surface pressure. A discussion of an efficient lift valve design is included. The changing of a gas lift system from some eight valves to fourteen valves and placing them in a so-called stacked condition is one of the more important features in increasing production. A discussion of gas lift valve choke sizes is included as well as the necessity for a high system pressure. In this case, pressure was increased from 900 psi to 1300 psi, thereby providing a lower gas injection point required for maximum production. point required for maximum production. By the proper analysis of a high volume gas lift System, production can be increased as much as 200% by carefully analyzing the following features:

- tubing size,

- operating pressure,

- surface wellhead restrictions, and

- the number and spacing of gas lift valves.

Once a system is considered to be operating at its maximum efficiency, it should not be neglected. Proper monitoring is as important as the initial design and installation. At least bimonthly well production tests should be conducted with complete production information recorded. This then provides necessary information prior to a workover whereby a complete system prior to a workover whereby a complete system analysis can be applied for the purpose of increasing production. production. Many beneficial changes can be made with very little expense if a Proper evaluation is conducted and analyzed.
3D Seismic Calibration to Measure Upper Jurassic Sand Porosity, North Viking Graben
Authors: Lowden D.J. , Hansen P.A.
Published: December 2007

Localized sand bodies can be found encased within widespread Upper Jurassic shales, preserved on the flanks of eroded paleo-highs in the North Viking Graben. They are often situated in structural lows, poorly represented by well control and highly heterogeneous. Moreover, they are difficult to identify using conventional seismic and their location even harder to predict using geological modelling techniques. However, these excellent quality sands provide stratigraphic traps that can be quantitatively mapped using borehole calibrated 3D seismic acoustic impedance.

The Statfjord Nord 3D seismic survey was shot and processed during the last decade. Recently, borehole calibrated processing was performed on the 3D survey to obtain seismic acoustic impedance from each seismic trace. An objective method was used requiring no a priori information to constrain the solution and hence was not dependent upon a geological model.

The 3D seismic acoustic impedance permitted discrimination of Upper Jurassic sands from adjacent shales by virtue of their unique acoustic signature. Sand effective porosity was computed for a subset of the 3D volume using relationships obtained from an acoustic-petrophysical study carried out using well data. The 3D acoustic impedance was converted to velocity, thus allowing the thickness to be obtained for each seismic time sample. This quantitative calibration of 3D seismic made it possible to objectively map porosity-thickness of Upper Jurassic sands.