bluuebunny/crossref_metadata_2025 huggingface dataset:
Nitrogen Minimum Miscibility Pressures
Authors: Sebastian H. M. , Lawrence D. D.
Published: December 2007

Miscible gas flooding has been used for enhanced oil recovery for many years. Considerable data exists for CO2 and enriched hydrocarbon flooding so that screening criteria can be applied to determine when miscible flooding with these gases could be successful. However, for nitrogen the data are much more sparse. Thus, previous screening tools are very imprecise. In fact, all four correlations for nitrogen minimum miscibility pressure available in the literature predicted miscibility pressures that were more than 1000 psi different from the measured value for more than a third of the data available in the literature.

This paper presents a new much more accurate correlation for nitrogen MMP. This correlation takes into account the effects of oil composition and reservoir temperature and matches all nitrogen MMP data in the literature within 750 psi. This correlation predicts that the nitrogen MMP of an oil decreases as the methane- or intermediate content of the oil increases, and that the nitrogen MMP increases as the mol weight of the oil increases. It also shows that the nitrogen MMP goes through a maximum as the temperature increases and that this maximum is a function of oil composition.

In addition, this paper summarizes available nitrogen MMP data and presents seven new data points.
Experimental Evaluation of a Single-Well Surfactant Tracer Test for a North Sea Oil Reservoir
Authors: Garnes J. M. , Kindem Erling , Skauge Arne
Published: December 2007

The paper addresses problems related to application of a single-well surfactant test (SWST) for a North Sea oil reservoir. Waterflooding an oil production well prior to a SWST by injection of seawater will change the oil properties in the wellbore region. Injection of unsaturated water with respect to hydrocarbon gas in a formation containing a volatile oil with GOR in the range of 100-1000, will cause stripping of the oil.

The injection of cold seawater may alter the temperature in the injection zone and this effect combined with the variation of GOR with distance from the wellbore will result in gradients both in temperature and oil properties. The effect of these variations will influence the phase behavior and the performance of the surfactants as well as the tracers.

Static multiple water-oil contact experiments at reservoir conditions have been performed. These experiments were compared to dynamic core displacements in- order to quantify the stripping of the oil phase by water. The tracer partitioning and hydrolysis were measured both in static experiments and reservoir cores. The effect of GOR on tracer partitioning was also investigated.

The results reveals that the GOR of the specific oil used was reduced from 110 to 10 and the formation volume factor (Bo) from 1.34 to 1.05. The decreasing gas content in the oil changes the phase behavior of the optimized surfactant system towards a lower phase microemulsion.

The surfactant system had to be re-optimized against the stripped oil both by static phase behavior and dynamic core displacements. The effect of stripping leads to a significant change in surfactant and tracer phase behavior. In addition, due to the changes in BO, the saturation values as determined by the tracer test yields low waterflood residual oil saturations compared to expected results of a large scale waterflood.
Measurement of Polymer Retention Levels Representative of the Formation
Authors: Goodyear S. G. , Johnston J. D. , Lawless T. A. , Woods C. L.
Published: December 2007

To assess the economic viability of a proposed polymer augmented waterflood and to design the treatment, it is necessary to determine the polymer retention level in the rock matrix.

Static adsorption experiments on crushed rock samples are unsuitable, because the crushing process may expose new sites, and mechanical entrapment of molecules in pores is not included in the measurements. Dynamic core-flooding measurements, at deep reservoir flow rates, are therefore required. However, reservoir core plugs may be contaminated by drilling muds, particularly at the ends, increasing the adsorption capacity. In this case, detailed mass balance calculations on the polymer effluent profiles may significantly overestimate retention levels in the formation.

To overcome these problems, a pyrolysis/beta scintillation counting technique has been developed. The core plug is flooded with 14C-labelled polymer. It is then disassembled and samples from the interior are crushed and pyrolysed, to convert the carbon to CO2. The 14C content of the gas is measured via beta-scintillation counting, giving the polymer retention level in the plug's interior, where face filtration and drilling mud contamination are minimised.

This paper describes the validation of the technique. The reproducibility and efficiency of the recovery are shown to be independent of the crushed particle size, over the range 50-1000 μm, the polymer retention level, over the range 1-120 μg/g, and the presence of oil at residual saturation. Finally, the retention levels deduced from a detailed mass balance calculation and subsequent pyrolysis/beta scintillation counting of samples from an uncontaminated core are compared, and found to be consistent.

This technique is recommended for the determination of polymer retention levels in the rock matrix, under as near as possible reservoir conditions, assuming that a small amount of 14C-labelled polymer is available.
Production Performance of the Wasson Denver Unit CO2 Flood
Authors: Tanner C. S. , Baxley P. T. , Crump J. G. , Miller W. C.
Published: December 2007

The Denver Unit, located in the Wasson Field of west Texas, is the world's largest Carbon Dioxide Enhanced Oil Recovery (EOR) project. Shell Western E&P Inc. initiated CO2 injection in the Denver Unit in 1983, utilizing CO2 from naturally occurring source fields in Colorado and New Mexico.

Production response to CO2 flooding has been impressive, with over half of the current daily oil production attributable to CO2 injection. In fact, oil production has substantially exceeded- original project performance predictions.

The project was- originally implemented with both a Continuous CO2 injection area and a Water-Altemating-Gas (WAG) CO2 injection area. A comparison of the performance of these two areas has clearly demonstrated the advantages of each injection method, and has led to the conversion of the the Unit to a "Denver Unit WAG" (DUWAG) injection process, which plays on the strengths of both injection schemes.

This paper will cover in more detail the observed production performance of the CO2 flood to date, present a comparison of the Continuous and Water-Altemating-Gas injection processes, and review the design and implementation of the Denver Unit WAG project. The paper will be of interest to companies who are either operating- or preparing to implement CO2 Floods.
Core Wettability Measurement by Dynamic Adsorption
Authors: Torske Lisa , Skauge Arne
Published: December 2007

The standard methods for determination of the wettability of reservoir cores (Amott and USBM) involve displacement of water- or oil, in presence of both the wetting and non-wetting phases.The result may depend on fluid saturations as well as on experimental procedure, causing uncertainties of the measured wettability.

The paper presents an attempt to determine the wettability of the core material independent of the fluid saturations.The method involves contacting the core with a reagent that selectively adsorbs either to the oil-wet- or to the water wet sites of the pore wall.Adsorption tests with several compounds have led to the selection of n-heptanol and methylene-blue as agents for wettability measurements by dynamic adsorption.

The area of oil-wet sites measured by n-heptanol adsorption from brine, is found to increase for silanized cores.Correspondingly, the fractional water-wet area of the core measured by methylene blue adsorption is reduced for silane-treated Berea cores compared to untreated cores.Wettability measurements are also performed on various cores from North Sea oil reservoirs.
Numerical Simulation of Hot-Water and Flue-Gas Injection Under Typical North Sea Reservoir Conditions
Authors: Fossum Bjorn , Blaker Tore , Brendsdal Egil , Johansen Thormod , Throndsen Torbjørn
Published: December 2007

This paper describes numerically simulated reservoir performance during the injection of hot water and flue gas at North Sea reservoir conditions. Studies of hydrocarbon/water phase behaviour at elevated temperatures and reservoir simulations showed that a hot water flood in a light-oil reservoir could increase the recovery by 3-9 % of the- original oil in place. A theoretical study of flue gas injection concluded that minimum miscibility pressure (MMP) for this gas was equal to MMP for an oil/nitrogen system. A nitrogen displacement was estimated to be immiscible at initial reservoir pressure and temperature, but miscibility would be developed at a slightly higher temperature.

The results predict that the combination of hot water and flue gas injection has a substantial potential for increasing the recovery from light-oil reservoirs.
Evaluation of Surfactants for CO2 Mobility Control in Dolomite Reservoirs
Authors: Kuehne D. L. , Frazier R. H. , Cantor Jeremy , Horn Willie
Published: December 2007

Laboratory studies were conducted to find the best surfactant for generating CO2 foam in the presence of residual oil for two dolomite reservoirs. Conventional anionic and nonionic surfactants did not foam very well in core tests at reservoir conditions. The poor performance was attributed to the oil-wet nature of the dolomite cores. A new surfactant formulation was developed that alters wettability and has much better oil tolerance. CO2 foams were generated easily with the new formulation and were more stable. Field tests are planned to demonstrate improvement of sweep efficiency using the new surfactant.

Evaluation of surfactants for mobility control applications involved a series of tests that measured brine compatibility, bench foam height, flow resistance in corefloods, and adsorption on reservoir rock. Bench foam tests, often used for surfactant screening, were unable to predict the effects of oil in the corefloods. Even the low oil saturation remaining after immiscible- or miscible CO2 injection was detrimental to foam generation. The new surfactant formulation works over a wide range of brine salinities, controls CO2 mobility better than conventional surfactants, and has moderately low adsorption on dolomite rock.
Effects of Gas and Liquid Velocity on Steady-State Foam Flow at High Temperature
Authors: Osterloh W. T. , Jante M. J.
Published: December 2007

Researchers have recently determined that capillary pressure plays a dominant role in controlling the texture, and hence the rheology, of foam flowing through a porous matrix. Of particular interest, the capillary pressure was found to reach a characteristic value, the limiting capillary pressure, at a relatively high fractional flow of gas, fg. If fg was increased further, the capillary pressure was reported to remain at the limiting value, the foam texture was coarsened, the liquid saturation remained constant, and the steady state foam pressure gradients were proportional to liquid velocity and independent of gas velocity.

The experiments in these recent reports were all performed at low temperatures. We report the results of foam flow experiments conducted at 150°C. The experiments were designed to characterize steady-state nitrogen foam flow by measuring pressure gradients in a 6.2 μm2 sandpack over a wide range of gas and liquid velocities and fractional flows.

We found that steady-state pressure-gradient responses, and hence foam rheology, could be divided into two distinct environments that were characterized by the value of fg. Interestingly, the pressure gradient response to gas and liquid velocity in one environment was exactly reversed in the other. In one environment, where fg was less than 0.94, the pressure gradient was dependent on gas velocity and was reasonably independent on liquid velocity. The pressure gradients were proportional to gas velocity to about the 0.31 power. In the other environment, where fg was greater than 0.94, the pressure gradients were dependent on liquid velocity and were reasonably independent on gas velocity. The pressure gradients were proportional to liquid velocity to about the 0.33 power. The transitions that occurred at fg of 0.94 likely correspond to the point at which the limiting capillary pressure was reached. The liquid saturation was low and nearly constant, about 0.06, in both flow environments.

At very high gas velocities, when fg was greater than about 0.998, steady-state flow was replaced by a chaotic-like flow in which the pressure gradient fluctuated and fell to very low levels in downstream sections of the sandpack.
Properties of Flowing Foam in Porous Media Containing Oil
Authors: Kristiansen T. S. , Holt Torleif
Published: December 2007

The spreading characteristics of a gas/oil/surfac-tant solution system depend on the interfacial tensions involved. This work indicates that systems having interfacial tensions giving spreading oil act more deleterious to foam stability as compared to nonspreading oil systems. The effect was demonstrated for Berea sandstone by changing the oil when the type of surfactant was unaltered and by changing the type of surfactant when the oil used was the same. For a slightly oil-wet reservoir rock a similar trend in foam properties was observed when the type of oil was changed.

In an oil spreading system the flow resistance of foam was found to increase with increasing concentration of the surfactant solution.
Phase Behavior Modeling Techniques for Low-Temperature CO2 Applied to McElroy and North Ward Estes Projects
Authors: Fong W. S. , Sheffield J. M. , Ehrlich R. , Emanuel A. S.
Published: December 2007

This paper describes a technique to model the behavior of three phase low temperature CO2 systems using two phase PVT algorithms, and its application to two field CO2 projects.

An approximate tuning procedure has been developed for using a two phase equation of state to characterize the displacement behavior of CO2 in the three phase domain. This characterization technique results in good prediction of laboratory slim tube displacement tests and the minimum miscibility pressure (MMP) for both pure and impure CO2 streams. Laboratory corefloods and field scale displacements can also be modeled to a practical level of accuracy. With this pseudo two-phase representation, complex three-phase flash calculations and the need for four-phase relative permeabilities are avoided.

This approach was used in forecasting the North Ward Estes CO2 project. Volume of mixing effects characteristic of low temperature CO2 systems are modeled in a vertical, fine resolution geostatistical cross section with a compositional simulator. Reasonable agreement with observed field performance is obtained. An immiscible CO2 huff-n-puff test at the McElroy field was also modeled, using a 2-D radial, compositional model. The cross section was derived from geostatistics. The simulation also provided a good approximation of field observation.
A Numerical Model for Predicting Alkali Slug Migration in Chemical Processes
Authors: Labrid J. C. , Le Thiez Pierre , Minssieux Louis
Published: December 2007

Use of alkaline agents in enhanced oil recovery is recommended in association with other chemicals such as surfactants and polymers, in- order to take benefit of synergistic effects which improve the cost efficiency ratio of chemical processes. One critical factor in these processes is to predict the transport of the alkali from the injection well to the production well. That is the aim of the flow model described in the paper.

The main physicochemical phenomena responsible for alkali consumption are taken into account in the model, i.e.

the reaction between alkali and acid components of crude oil,

the reactions of injected alkali with reservoir brine and minerals,including dissolution and ion exchange phenomena.

As far as dissolution processes are concerned, a previous work has shown that they are kinetically dependent, even at field scale, and that the thermodynamic equilibrium assumption is not valid. Kinetic equations are used that take into account the inhibiting effects of compounds formed during dissolution.

A methodology is developed to obtain the parameters needed for numerical simulation. This methodology is applied to natural consolidated sandstone rocks containing clay minerals. A satisfactory agreement is observed between simulation results and experimental data provided by batch tests and flow experiments. The model can be used to calculate the transport of the alkali slug at field scale and to help the selection of operating parameters such as type and concentration of alkali, and size of the alkaline slug.
Foam Treatment of Producing Wells To Increase Oil Production at Prudhoe Bay
Authors: Krause R. E. , Lane R. H. , Kuehne D. L. , Bain G. F.
Published: December 2007

Since May of 1989, the Prudhoe Bay oil field has been on decline. No longer limited by the capacity of the TransAlaska Pipeline- or state offtake restrictions, daily oil production is now restricted primarily by the amount of gas reinjection capability that currently exists at the North Slope.

This paper describes the results of several Prudhoe Bay field trials performed in 1991 in the Eastern Operating Area (EOA) by ARCO Alaska, Inc. The objective of these field trials was to assess the effectiveness of foamable EOR surfactants in preferentially reducing the gas production through direct treatment of high gas/oil ratio (GOR) producing wells. Three different methods of delivering the surfactant into the producing interval were tried. One method, the injection of foam, preformed at the surface using nitrogen, caused a significant GOR reduction which translated into an increase in oil production in the target well for a period of several weeks.

Work is ongoing in this area to determine the effectiveness and economic potential of these foam treatments.
Reduction of Oil and Water Permeabilities Using Gels
Authors: Liang J. , Sun H. , Seright R. S.
Published: December 2007

Several previous researchers reported that polymers- or gels can reduce permeability to water more than to oil. However, a plausible explanation for the phenomenon is not yet available. This property is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. We examined how different types of gels reduce oil and water permeabilities in Berea sandstone. The gel formulations that we investigated included (1) resorcinol-formaldehyde, (2) Cr3+(chloride)-xanthan, (3) Cr3+(acetate)-polyacrylamide, and (4) colloidal silica. Several new methods were applied to obtain a better understanding of why gels can reduce water permeability more than oil permeability. First, before gel placement in cores, multiple imbibition and drainage cycles were performed in both flow directions. Results from these studies established that hysteresis of oil and water relative permeabilities was not responsible for the behavior observed during our subsequent gel studies. Second, several gels clearly reduced water permeability significantly more than oil permeability. Whereas previous literature reported this phenomenon for polymers and "weak" polymer-based gels, we also observed the disproportionate permeability reduction with a monomer-based gel (resorcinol-formaldehyde), as well as with both "weak" Cr3+(chloride)-xanthan and "strong" Cr3+(acetate)-HPAM gels. In contrast, a colloidal-silica gel reduced water and oil permeabilities by about the same factor. Residual resistance factors for several gels were found to erode during multiple cycles of oil and water injection. In spite of this erosion, the disproportionate permeability reduction persisted through the cycles for most of the gels. Studies using both oil and water tracers provided insight into the fraction of the pore volume occupied by gel. The strongest gels appeared to encapsulate the- original residual oil saturation—thus rendering the residual oil inaccessible during subsequent oil flooding.
Comparison of Conventional Cyclic Steaming and Steamflooding in a Massive, Dipping, Midway Sunset Field Reservoir
Authors: Harrigal R. L. , Clayton C. A.
Published: December 2007

Two thermally enhanced oil recovery methods, cyclic steaming and steamflooding, have been investigated by means of numerical modeling for a massive, dipping, Midway Sunset Field reservoir. Comparative economics have been evaluated for the development alternatives.

The results of the investigation indicate that ultimate recovery efficiency is not sensitive to the method of steam delivery to the reservoir. Cyclic steaming methods recovered the same percentage of- original oil in place as did steamflooding. The cyclic operations required several times longer than steamflooding to reach the same ultimate recovery efficiency.

On a steam utilization efficiency basis (oil to steam ratio), cyclic steaming with small steam slug volumes proved to be the most efficient recovery method. As the rate of steam injection increased, the steam utilization efficiency decreased, regardless of the manner in which steam was delivered to the reservoir.

Despite having the poorest steam utilization efficiency, steamflooding provided far superior economics as compared to conventional low- or moderate slug volume cyclic steaming. This is directly attributable to steamflooding having the fastest rate of increase in average reservoir temperature and therefore the greatest rate of net recovery as compared to the alternatives investigated. Steamflooding exhibited a much quicker payout of development capital and a greater present value return per dollar invested.
Development Strategies for a Heavy-Oil (3,500 cp) Reservoir at a Depth of 2,100 ft (ss)
Authors: Singh K. S.
Published: December 2007

The Cruse ‘E’ reservoir in the Guapo field is located at a depth of 2100 ft., in the Southern Deltaic Basin of Trinidad. The reservoir fluid is 14° API with a viscosity of 3500 cp. Production is by thermal stimulation encompassing several operating strategies which were adopted and evaluated. The context of the evaluation includes areal and vertical sweep efficiencies relative to recovery per unit time.

This paper therefore has as its objective, the discussion of the following strategies and their impact on production efficiency:

Well spacing and pattern size. Reservoir heating and pressure distribution. Injection rates and pressures. Economic phasing of investment. Energy losses due to high friction in production facilities.
Laboratory Studies of Parameters Involved in Modeling Microbial Oil Mobilization
Authors: Bryant R. S. , Bertus K. M. , Stepp A. K. , Chang Ming-Ming , Chase K. L.
Published: December 2007

Microbial methods for increasing oil recovery are potentially cost-effective even at relatively low crude oil prices. Microbial formulations can be applied in a variety of methods including permeability modification treatments and microbial-enhanced waterflooding. The flexibility and potential cost-effectiveness of the technology make it attractive, but further understanding of the transport mechanisms of microorganisms and the development of a sound engineering methodology for optimizing microbial formulations and injection strategies are needed to realize its potential.

Work on this project has included the continuing development of a three-dimensional, three-phase, multiple-component numerical model to describe microbial transport phenomena in porous media. Laboratory data were used to develop correlations and mathematical models for specific phenomena; linear coreflooding data were used to test the simulator in an iterative process. The simulator development and laboratory testing aspects of this project were coordinated so that the results could be used to design other laboratory experiments to clarify and quantify certain physical and chemical effects. An accurate reservoir simulator for MEOR methods can best be developed through an integrated program of acquisition of laboratory and field data with the feedback loop being the reservoir simulation model.

From our concepts of the hydrodynamics, physics, chemistry and microbiology of MEOR processes, microbial parameters incorporated into the microbial transport model include: (1) microbial growth and decay; (2) microbial deposition; (3) chemotaxis; (4) diffusion; (5) convective dispersion; (6) tumbling; and (7) nutrient consumption. Laboratory experiments were conducted to obtain actual data for the simulator regarding microbial growth and decay, nutrient consumption, microbial deposition, convective dispersion, and diffusion. Unsteady-state relative permeability measurements using microbial formulations were made to determine the effects of microbial metabolites on fractional fluid flow in porous media. Mechanisms considered to be important for oil recovery include changes in microscopic properties such as interfacial tension, wettability, and adsorption that govern oil mobilization and affect fractional flow and relative permeabilities. Other oil recovery, mechanisms traditionally associated with fluid flow changes include polymer and biomass production by microorganisms. This paper describes the laboratory investigations conducted in our ongoing efforts to incorporate oil recovery mechanisms by microorganisms into the simulator. Computer tomography studies demonstrated that gas production by microorganisms can reduce residual oil saturation in porous media. After conducting field-scale numerical simulation studies using data from relative permeability experiments, it was determined that microbial treatment could improve oil recovery over waterflooding alone.
New Field Simulation Strategy With Detailed Element Models and Flux Boundary Conditions: Statfjord Field Case Study
Authors: Aadland Atle , Henriquez Adolfo
Published: December 2007

Full field reservoir simulation has been adequate for reservoir management purposes for more than a decade long production history of the Statfjord Field in the North Sea. At the present stage, the beginning of production decline, the simulation strategy needs to be changed. A full field model would be unmanageably large if the geological detail needed to understand the issues relevant to further recovery enhancement is included. Most of the remaining reserves will be recovered by sidetracking and infill drilling. The remaining oil has then to be mapped carefully using both the geological information obtained during these years together with a reliable history matching. In this paper, a methodology has been developed for history matching regions with very detailed geology, while taking into account the interaction with the whole reservoir. The method involves writing to a history file the fluxes between the cells at the boundaries of the regions of interest and the rest of the reservoir. This methodology has been tested for the Statfjord Field. The CPU-time was reduced by 35 percent compared to a conventional method. The insights obtained were achieved in a shorter time. The fluid flow processes are better represented and the reservoir description obtained is more representative. Furthermore, the element model is now run in prediction mode as a tool for reservoir management and planning well activities. Thus a new simulation strategy, based on history matched, geologically detailed element models and preserving the interaction with the whole reservoir, has been proved useful.
Interactive Visualization of 3D Complex Geological Structures
Authors: Pajon J-L. , Rainaud J-F.
Published: December 2007

The aim of this paper is to show how simple computer graphics tools can be used to visualize complex geological configurations. Once that a geologist has modeled various geometries by assembling structured grids, these tools offer him the possibility to explore them in various interactive ways. Different visualization modes give a faithful representation of these data, and direct manipulation with a mouse of the most important parameters that govern this representation allows a fast, easy, attractive and enriching dialogue between the user and its simulation. Some tools for determining and visualizing the intersection of two grids are also available.
Hypertext-Based GUI for Reservoir Engineering Software
Authors: Blanc Georges , Givaudan Abel , Betoin J-P. , Van Den Zande Didier , Vives Eric
Published: December 2007

This paper describes the development of two software tools:

A Graphical User Interface (GUI) based SCREEN MANAGER; A HYPERTEXT based Language;

to be used to build PRE and POST processors of reservoir engineering software.
Increasing Production Using Microprocessors and Tracking Plunger-Lift Velocity
Authors: Morrow S. J. , Rogers J. R.
Published: December 2007

The increasing recognition of Plunger-Lift as a viable method for producing many wells, has brought a number of changes to the technology involved. The importance of proper plungerlift performance criteria (as reported in an earlier SPE paper) has been recognized and steps taken to incorporate this information into modern day control systems.

This paper discusses the usage of plunger velocity in establishing operating cycles for gas wells and for oil wells. When used in conjunction with state of the art electronic microprocessors. the results are increased production, extended economic limits. less down-time, and many others. This has been proven to be the case in both conventional and slim-hole wells.

Primary areas of discussion are:Relativity of plunger velocity insofar as efficiency is concerned.Standard approach historically taken to achieve maximum production.New software design that automates cycle changes while increasing production and reducing both man-hours and down time.Test results and case histories.

Results, Observations and Conclusions:

Significant production increases have been realized in the vast majority of wells produced via this method. Modest increases were realized on the remainder of wells tested. Optimization, by using plunger travel velocity has proven to be highly successful. Increases in excess of 100% realized on many gas wells. Reducing down-time, saving man-hours, increasing production rates, handling line pressure changes and generally eliminating the most common problems associated with plunger-lift are the result of this approach.

Applications:Gas well dewatering, even for marginal producers. For both conventional and slim-hole wells.High GLR wells.Wells with high or fluctuating sales line pressures.
Comprehensive Processor-Based System for Liquid Removal From the Wellbore and Formation of Loading Gas Wells
Authors: Gregg D. P.
Published: December 2007

This paper describes the current systems that are being developed and used in the petroleum production industry with processors and electronics that are currently available to the designer for production controls. It highlights the transition from mechanical to the initial attempt at electronics through the discreet systems of operation to the current designs that are providing a complete integrated overview of the well and its requirements to produce.

This paper discusses the ability of various operating and production philosophies to now be developed into actual working systems of specified formats and yet yield varied results due to those concepts that are applied. The truly innovative approach has now a means of becoming a reality in the processor based system. The overview of the current concepts is evaluated to show its current merit in today's need for efficient and truly effective stand-alone production systems.
Determination of the Maximum Water-Free Production Rate of a Horizontal Well with Water/Oil/lnterface Cresting
Authors: Guo Boyun , Lee R. L.
Published: December 2007

The number of horizontal oil wells has been increasing rapidly in the past few years because of several advantages of their application. However, further improvement of oil production rate of horizontal wells is limited by the encroachment of the water crest when bottom water exists. This paper focuses on the theoretical and numerical analysis of water-oil-interface cresting behavior in horizontal wells. The objectives of this investigation include: (1) to find a simple approach to determination of the maximum water-free production rate of horizontal wells with water-oil-interface cresting, and (2) to determine the location of the water-oil-interface under critical condition.

The maximum water-free oil production rate (critical rate), which is defined as the oil producing rate at which the unstable water crest forms, is determined analytically for horizontal oil wells using conformal mapping theory. The resulting solution shows that the critical oil production rate is proportional to the conductivity and thickness of the oil reservoir, and water-oil density contrast. This critical oil rate is also a function of the critical crest height and wellbore location in the oil bearing formation.

The lateral extension of the water crest under critical condition is also determined analytically. This solution indicates that the water-oil-interface cresting is a local phenomena in an oil reservoir. The water crest extends laterally within one thickness of the oil reservoir.

Example calculations are confirmed by a numerical reservoir simulator which has matched field data. This solution provides a new approach to evaluating performance of horizontal wells.
Dolphin Field: A Successful Miscible Gas Flood in a Small Volatile Oil Reservoir
Authors: Stright D. H. , Fallin W. S.
Published: December 2007

Dolphin Field was discovered in October, 1986. The reservoir initially contained 6.3 MMSTB of an undersaturated volatile oil which is miscible with hydrocarbon gas at 4000 psi. Gas injection was initiated in October, 1988 with recovery to date of 31% of the original oil-in-place (OOIP). The ultimate recovery is expected to be 51% of the OOIP, which is 2.7 times the estimated recovery without gas cycling.

This case history paper outlines field development and engineering analysis leading up to initiation of gas injection, and performance review of the project. The Dolphin Field project demonstrates (1) how hydrocarbon recovery from a relatively small oil reservoir can be significantly increased with miscible gas injection and (2) how early reservoir characterization prevented production below the bubble point pressure, which would have eliminated the chance for the additional oil recovery.
Acid Fracturing with New Fluid-Loss Control Mechanisms Increases Production, Little Knife Field, North Dakota
Authors: Sanford B. D. , Dacar C. R. , Sears S. M.
Published: December 2007

Acid fluid loss due to wormholes is extremely difficult to control. It is generally considered to be the major factor limiting the effectiveness of acid fracturing treatments in carbonate formations. A new acid fracturing fluid has been developed to control fluid loss. With unique characteristics, this new fluid loss system is highly efficient and allows the acid to penetrate deeply into the fracture, resulting in superior stimulation.

This paper discusses the technical design and results obtained utilizing this new acid stimulation fluid in the Little Knife Field, Williston Basin, in North Dakota. Production comparisons show a substantial improvement in well performance from these wells following acid fracturing treatments. This new acid stimulation system improves live acid penetration in a naturally fractured carbonate reservoir, thus sustaining greater and longer production increases than prior stimulation treatments.
A Reservoir Analysis of the Dakota ‘A’ Sands, Cole Creek Field, Wyoming
Authors: Towler B. F.
Published: December 2007

The Cole Creek field is located in the western margins of the Powder River Basin about 15 miles north east of Casper in T 35 N and R 77 W. Discovered in 1935 it has produced from the Cretaceous horizons, the Shannon, Frontier, Muddy, Lakota and Dakota sandstones. This paper discusses the potential remaining in the Dakota Channel sands running across the south eastern nose of the structure. The Dakota has only been produced from two areas in the reservoir, the first being the poorer quality sands on the crest of the structure and the second being the so called channel sands on the southern nose which was partly developed because the productivity of the Dakota wells was higher in that area. It was not clear whether these channel sands are in communication with the crestal sands or whether there are several separate Dakota reservoirs around the structure. The Cole Creek field is principally a structural trap but to understand the reservoir it is important to determine to what extent stratigraphy and hydrodynamics plays a part in the Dakota trapping mechanisms. In this paper i examine the geology, production trends, pressure, rock and fluid data in order to determine the initial oil in place, recovery factors, drive mechanism, and ares of bypassed oil, all of which will shed light on the future potential of the reservoir. It is hoped that all of this data will then be used in a reservoir simulation study to quantify the development potential of the reservoir.
An Analysis of Hydraulic Fracture and Mineback Data for a Treatment in the German Creek Coal Seam
Authors: Jeffrey R. G. , Brynes R. P. , Lynch P. J. , Ling D. J.
Published: December 2007

A hydraulic fracture treatment in well ECC90 of the German Creek coal seam was carried out in March, 1989, at the German Creek Mine Central Colliery located in the Bowen Basin of east central Queensland to assess hydraulic fracturing of coal seams in vertical boreholes as a means of stimulating drainage of methane from the seam in advance of mining. The main goals of the project were to measure the size and geometry of the fracture formed and to test the effect that such a full-scale treatment might have on later mining operations. The plan also included dewatering the coal and producing methane from the well after stimulation. In ECC90, the German Creek seam is located 722 feet [220 m] below the surface and has a thickness of 8.3 feet [2.5 m].

During the stimulation, 80,200 U.S. gallons [303,000 1] of crosslinked gel containing about 80,500 pounds [36,590 kg] of sand were injected into the coal seam at an average rate of 30 barrels per minute [4,763 1pm]. The surface treating pressure averaged about 900 psi [6.2 MPa] and decreased slowly during the treatment except near the end of the job when it increased sharply (because of a screenout).

The fracture, exposed by mining, had a large horizontal component overlying a less extensive vertical fracture. The propped width varied from zero to 7.9 inches [200 mm]. No fracture penetration into over- or underlying rock layers was observed and the mining operations were not significantly affected by the presence of the hydraulic fracture.
Measurement of Fluid Velocities During Water Injection Into Natural Porous Rocks
Authors: Robinson M. A.
Published: December 2007

Magnetic resonance imaging (MRI) is used to measure flow velocities in Casper sandstone and San Andres dolomite. The cores are initially saturated with water, and the flow velocities are monitored during water injection. Such results are useful in determining how much of a core is contacted during a coreflood experiment.
Pressure Transient Testing of Horizontal Wells in Coalbed Reservoirs
Authors: Engler T. W. , Rajtar J. M.
Published: December 2007

Coalbed methane gas resources have become a significant part of the total United States gas reserves. Recently, many completions in coalbed reservoirs are horizontal. Coal is an anisotropic, naturally fractured medium, comprised of a low permeability matrix surrounded by a high permeability fracture "cleat" system. The anisotropy makes a coalbed reservoir a good candidate for horizontal completions in order to intercept more fracture areas. This paper addresses horizontal well testing in coalbed reservoirs.

The majority of the gas in coalbed reservoirs is stored in an adsorbed state on the coal grain surfaces. To mobilize this gas requires a pressure drawdown across the matrix boundary, which is created by the depletion of the cleat system.

The paper presents the drawdown and buildup solutions for a horizontal well in a coalbed methane gas reservoir. Pseudosteady state gas desorption and uniform pressure distribution along the well is assumed. A solution is obtained for anisotropic, semi-infinite reservoir with constant rate production at the well. Successive Laplace and Fourier integral transforms are applied with numerical Laplace inverse transform. The match of analytical solution with numerical simulation data is presented.

Investigations into the effects of the diffusion coefficient D, and sorption parameter θ, are presented.
Pressure Buildup Analysis of Low-Rate Pumping Wells in the Haas Field, North Dakota
Authors: Ohaeri C. U. , McCarrel D. A. , Koliba R. J.
Published: December 2007

This paper documents a procedure used to analyze acoustic pressure buildup data from low flow rate pumping wells in the Haas field North Dakota. Because of excessive wβllbore storage on these tests, the analysis method uses pressure rate deconvolution to eliminate or minimize the wellbore storage effect This results In tests which are economic to run. Furthermore, analysis of the deconvolved data yields results comparable to those obtained from longer duration test Even though we compute the flow rate and pressure from acoustic fluid level measurements, nevertheless, our analysis procedure is general in nature and is applicable to pressure buildup tests for which afterflow rate and pressure data are available.
Performance Characteristics of Vinylsulfonate-Based Cement Fluid-Loss Additives
Authors: Mueller D. T.
Published: December 2007

Vinylsulfonate fluid loss additives, based on the 2-acrylamido-2-methylpropane sulfonic acid (AMPS™) monomer, are in common use in field cementing operations. The eopolymerization of AMPS™ with conjugate monomers yields a fluid loss agent whose properties include: (1) minimal retardation; (2) salt tolerance; (3) high efficiency; (4) thermal stability; and (5) excellent solids support.

The performance characteristics of AMPS™ based fluid loss additives (ABFLA) are primarily dependent on two factors: the temperature state of the system and the physical parameters affecting polymer hydration. At temperatures below 200°F (93°C) ABFLA exhibit a "threshold" response between fluid loss control and polymer concentration. This distinct transition in fluid loss efficiency takes place at a specific ABFLA loading known as the critical polymer concentration (CPC). Below 200°F (93°C) ABFLA also possess an interrelationship between rheological character and fluid loss control. When the CPC for a particular slurry is reached, the yield value as measured by the 6 and 3 RPM Fann readings will fall dramatically from "neat" values, and good fluid loss control will ensue. As the temperature condition rises above 200°F (93°C), the response of fluid loss control to polymer concentration becomes more linear in nature. Additionally, fluid loss efficiency becomes increasingly influenced by factors such as polymer hydration time and the pressure and salinity environment under which hydration takes place.

ABFLA are powerful implements for the cement technologist. Knowledge of the unique performance characteristics of ABFLA is necessary for proper slurry design, test data interpretation, and recommended job procedures, all significant factors in the success of a field cementing operation.
Use of an Active Object-Oriented Process To Isolate Workstation Applications From Data Models and Underlying Databases
Authors: Aronstam P. S. , Middleton J. P. , Theriot J. C.
Published: December 2007

Among the greatest problems facing the petrotechnical software developer today is the rapid evolution of database technology and data model issues. In order to be commercially successful, applications must coexist with a wide range of existing database implementations, and in many cases, multiple different databases feeding a single application. With the increasing cost of re-engineering on increasing numbers of applications, it is essential to adopt a single strategy which can bridge existing data systems as well as the inevitable future evolution in database technologies.

This paper discusses the design of an object-oriented process for petrophysical applications, which provides isolation from data model and access technology, optimization of data available at run time to the application, and supports concurrent use of data by multiple clients in a single session.

In operation, all data requests from clients are sent via interprocess comriiunication to the object manager. Objects are dynamically created as required. The code to load data from the underlying database into memory in optimized form are isolated within the objects. Through inheritance of the object class structure, the necessary changes to accommodate varied data access systems is minimized. Pointers to data are returned through the object manager to the requesting client. Memory management, including anticipation of next client requests, are handled by the object manager.

Additionally, this scheme permits multiple client processes to attach to the same data object allowing a dynamic link between processes to update calculations on shared data.
An Improved Steamflood Analytical Modeling Tool: Updating Old Methodologies With New Approaches To Increase Engineering Productivity
Authors: Harrigal R. L. , Wilcox G. G.
Published: December 2007

During the past 30+ years of steamflood application, significant advances have been made in understanding the complex displacement mechanism of heavy oil by steam. The mathematical simplification of the many complexities of the process into analytical expressions has contributed greatly to the speed with which the typical Engineer gains knowledge concerning the probable performance of a project.

While some steamflood analytical models can provide performance predictions of acceptable accuracy, they usually do so by assuming that the displacement process is either completely horizontal, so called piston-like, or completely vertical, so called gravity override dominated. Since the performance estimates that result are very different for the two types of displacements, this assumption has proved quite limiting. Not only can it lead to the misapplication of the models, it virtually eliminates the connection between process dynamics and performance estimation.

A personal computer based tool has been developed such that reliable performance estimates are obtained regardless of the direction of oil displacement by steam, and provides a strong tie between process dynamics and performance prediction. While the tool provides significant enhancements, the time efficiency of a very simple tool is preserved. This paper describes the analytical methodology utilized, its software and hardware platforms, and illustrates its application.
Development and Application of an Integrated Petroleum Engineering and Geologic Information System in the Giddings Austin Chalk Field
Authors: McGowen H. E. , Krauhs John
Published: December 2007

This paper relates the success of applying microcomputers to quickly and accurately analyze a large mature field. The objective of this study was to combine historical and ongoing activity with geologic information to locate restimulation, recompletion and horizontal drilling potential in the Giddings Austin Chalk field. The project was divided into four segments: system design, software development, data analysis and project implementation. The end product was a custom analysis system which allowed the operator to economically add reserves through restimulation and recompletion projects.