bluuebunny/crossref_metadata_2025 huggingface dataset:
Encapsulated Scale Inhibitor for Use in Fracturing Treatments
Authors: Powell Ronald J. , Fischer Arlan R. , Gdanski Rick D. , McCabe Michael A. , Pelley Samuel D.
Published: December 2007

This paper describes the development and testing of a solid, encapsulated scale inhibitor for use in fracturing treatments. Data from laboratory and field tests are reported. Laboratory testing with a continuous flow apparatus has yielded inhibitor release rates under dynamic conditions. The inhibitor was tested to determine the minimum inhibitor concentration required to inhibit the formation of CaCO3, CaSO4, and BaSO4 scales in brine. Laboratory data were used to determine the parameters of a mathematical model to predict the long-term release rate of the inhibitor. Data from a treated well are compared with predictions of the model.

Release-rate testing in a continuous-flow apparatus shows that an encapsulated solid derivative of a phosphonate inhibitor has a sustained release profile. Temperature (100° to 225°F) and brine strength have a small effect on the release-rate profile. Coating the solid derivative makes it compatible with metal-crosslinked fracturing fluids. The coating has a short-term effect on the release-rate profile. The composition of the solid derivative has the greatest effect on its long-term release-rate profile.

A comparison between the mathematical model proposed to describe the long-term release rate of the inhibitor and actual data collected from a treated well shows a large discrepancy, likely because most of the inhibitor is not in contact with the water being produced from this well.
Development and Application of a New Upscaling Technique
Authors: Lee Jaedong , Kasap Ekrem , Kelkar Mohan G.
Published: December 2007

Detailed reservoir descriptions have become available with the advent of geostatistical conditional simulation and geological-engineering reservoir characterization techniques which can honor and integrate information such as core, well log, well test, geological and geophysical data. Prohibitive computational costs of flow simulations with such detail limit us to coarse grid systems. Of all the reservoir properties, permeability has the foremost effect on fluid flow. Therefore a procedure to properly scale-up small scale permeabilities to a permeability of a large scale coarse grid is needed.

This paper presents an extension of the new 3-D absolute permeability analytical upscaling method by incorporating 3D directional search and coordinate rotation procedures. The method for single-phase upscaling is applied to realistic 3-D reservoir heterogeneities and Glenn Pool Self Unit flow simulations and excellent agreement is obtained between fine and upscaled coarse grid simulations.

The paper also presents the extension of the method to relative permeability upscaling. Based on phase permeabilities, a theory of analytical upscaling for waterflooding has been developed. The method assumes steady-state flow under capillary-viscous equilibrium and calculates effective relative permeability tensors based on phase permeabilities as a function of water saturation. The preliminary results of the new two-phase analytical upscaling method in 2-D are compared with numerical results and a promising match is obtained. The new method may present a viable alternative to numerical upscaling.
A Critical Evaluation of a Steamflood Pilot in a Deep Heavy Carbonate Reservoir in Ikiztepe Field, Turkey
Authors: Nakamura S. , Sarma H. K. , Umucu T. , Issever K. , Kanemitsu M.
Published: December 2007

This paper presents an evaluation of a 4,430-ft deep steamflood pilot being carried out jointly by the Japan National Oil Corporation (JNOC) and Turkish Petroleum Corporation (TPAO) in collaboration with the Japan EOR Research Association (JEORA) in the Sinan heavy oil reservoir of the Ikiztepe field, Turkey. The paper discusses pilot operations and performance highlighting the problems and the corresponding remedial measures/solutions adopted. Also presented is a discussion of results of an integrated simulation history match study. The pilot is in its final phase, and has so far yielded oil-steam ratios (OSR) of 3.42 and 0.32 during the initial cyclic steam stimulation phase and the steamflood, respectively.
Hot Dry Rock: A Versatile Alternative Energy Technology
Authors: Duchane D. V.
Published: December 2007

Hot dry rock (HDR) is the most abundant geothermal resource, and is found almost everywhere at depth. The technology to extract energy from HDR for practical use has been under development at the Los Alamos National Laboratory for more than twenty years. During the 1970’s, the possibility of mining the heat from HDR by circulating water through an engineered geothermal reservoir was first demonstrated on a small scale. Between 1980 and 1986, a larger, deeper, and hotter HDR reservoir was constructed. This large reservoir was subsequently mated to a permanent surface plant. A number of flow tests of this large HDR reservoir were conducted between 1991 and 1995. The results of these tests have indicated that it should be practical to operate an HDR heat mining facility to produce power on a sustained basis.

An industry-led, government cost-shared project to produce and market energy generated from HDR is currently being put in place. That project should help demonstrate that HDR reservoirs can be operated to provide energy for long periods of time at rates sufficient to be commercially viable. In the longer run, additional applications of HDR technology such as water and waste treatment, and steam generation for oil field flooding may come into widespread use.
Water Movement Surveillance with High Resolution Surface Gravity and GPS; A Model Study with Field Test Results
Authors: Brady J. L. , Wolcott D. S. , Daggett P. H. , Ferguson J. F. , Hare J. L. , Aiken C. L. V. , Balde M. , Seibert J. E. , Mader G.
Published: December 2007

A unique method to monitor gas cap water movement in an Arctic environment has been developed and tested. The novel surveillance technique for monitoring the water movement had to be developed given the very limited number of wells that penetrate the gas cap. Conventional fluid monitoring techniques require drilling numerous observation wells to adequately monitor water movement. Modeling studies indicate that density changes associated with water replacing gas can be detected using high-resolution surface gravity measurements. Modeling gravity effects of water movement mass distribution, mass balance and water front detection are discussed. A test of the gravity meter and essential high precision station positioning under typical Arctic winter conditions is evaluated using the Global Positioning System (GPS).

Modeling results have shown the general shape of the water front can be detected using surface gravity with μGal precision. With high precision gravity measurements, greater than 90% of the increased water can be accounted for in the resulting gravity anomaly. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average water front can be reliably detected within a producing well spacing (approximately 2000 ft (610 m)). Surface gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (-44° F) accurately enough to monitor the water movement (surface gravity = ±5 μGals: GPS = ±1 cm elevation). In fact, this was the first high precision gravity survey using a GPS antenna as an integral part of the surface gravity meter housing.
Horizontal Well Applications in a Miscible CO2 Flood, Sundown Slaughter Unit, Hockley County, Texas
Authors: Guillot Stephen N.
Published: December 2007

Horizontal wells were seen as a potential way to improve CO2 flood economics by increasing injection rate and improving areal sweep. The effect of horizontal injection wells on vertical sweep in a layered reservoir needed to be determined. Texaco planned to drill two horizontal CO2 injection wells as a pilot. Nearby observation wells would be used to monitor flow in the reservoir.

More wells were planned as a result of a decision to not operate a CO2 flood in a densely populated area. Seven wells in the city of Sundown were plugged and abandoned. Three horizontal producers and one horizontal injector were drilled directionally from locations outside town to replace the plugged wells.

This paper summarizes the planning, implementation, and post-drill analysis of these six wells. The seventh and eighth wells have recently been drilled and are mentioned briefly.
Behavior of Water Cresting Under Horizontal Wells
Authors: Permadi P. , Lee R. L. , Kartoatmodjo R. S. T.
Published: December 2007

Complex reservoir flow problems could be better understood through a study using physical models. The purpose of this paper is to present results of an experimental study of water crest behavior under horizontal wells. This work is made in an effort to better understand the formation and growth of water crest prior to and after water breakthrough. The physical model constructed differs from others in that variation in length and position of the horizontal well can be made. Eighteen different systems with varied oil column thickness and oil viscosity were run. Particularly in systems with viscous oil, the bottom water never reached the tip end of the well even at a producing water cut of almost 100 percent. The end effects defined as the unswept oil are pronounced as the well length is reduced and as the oil viscosity is increased. Also, at high water cut, the portion of the wellbore with low productivity increases with well length. These physical occurrences have not been previously reported. Postbreakthrough performance will be presented and discussed.
Exchange Of Producing Properties To Improve Operating Efficiency, Establish Capital Value Of Reserves And Reduce The Need For Depletion Allowance
Authors: Slobod Robert L.
Published: December 2007

Recent changes in the federal tax law regarding depletion allowance focus attention an the taxation problems of oil and gas production. In this paper we present the idea production. In this paper we present the idea of exchanging (selling) producing properties among operating companies in order to improve operating efficiency. As a result of such exchanges and in addition to the engineering advantages, a capital value for the reserves in the ground will be established for each purchase. In this way, a taxable deduction purchase. In this way, a taxable deduction will be clearly established. We should also realize that the seller will become liable f a capital gains tax when he sells at a profit An important finding is that the higher the price paid in the exchange, the better is the price paid in the exchange, the better is the tax picture. Not only is the tax liability converted to a capital gain situation, but if the price is high enough, a paper loss will be established which will further help the tax picture. This idea is presented with the aim picture. This idea is presented with the aim that it be given further thought and evaluation by the industry as a means of making the industry less dependent upon the depletion allowance for fair taxation.

Introduction

Efficiency in the production of oil could be improved in many reservoirs if the operator could consolidate his holdings. Such a consolidation could be achieved by selling the many isolated leases in different fields and in turn purchasing groups of adjacent or nearby leases in the same producing horizon. In this way more efficient production units could be assembled.

Such lease trades will also have serious and perhaps beneficial effects on the tax obligations of the operator. For example, any gains resulting from the sale of a lease will probably be eligible for the benefits of probably be eligible for the benefits of long-term capital gains. Also, as a result of the purchase of a lease, the operator will have purchase of a lease, the operator will have established a capital value for the reserves. This action will somewhat decrease the dependence on the depletion allowance for fair tax treatment with respect to taxing capital. The effect of the transfer of producing properties on tax obligations and, in particular, its relationship to the depletion allowance is the main subject of this paper.

The subject of depletion allowance is prominent in our thinking these days because of prominent in our thinking these days because of the current changes in the tax laws. By way of review, we should recall that depletion allowance has two main justifications. The first is to encourage exploration. We shall not be dealing with this objective in this discussion. The second purpose is to avoid taxing capital. We should recall that it is part of the tax philosophy in this country that the income tax philosophy in this country that the income tax should not be a tax on capital.
Gas Condensate Reservoir Behaviour: Productivity and Recovery Reduction Due to Condensation
Authors: Barnum R. S. , Brinkman F. P. , Richardson T. W. , Spillette A. G.
Published: December 2007

The depletion of gas condensate reservoirs to pressures below the dew point has been studied by reservoir engineers for many years. Pressure decline below the dew point pressure causes condensation to occur which creates a hydrocarbon liquid saturation in the reservoir. This process reduces liquid recovery and may reduce gas productivity and gas recovery. Exxon experience, particularly in low-productivity, high-yield gas condensate fields, suggests that liquid condensate formation can result in severe loss of well deliverability and therefore of gas recovery. This study was undertaken to evaluate the historical frequency and severity of productivity impairment due to near-wellbore condensate buildup and to identify reservoir parameters associated with severe productivity and recovery reduction.

This study of gas condensate reservoirs included a survey of Exxon and published industry experience, a review of published laboratory data, and simulations with single well flow models. Data from 17 fields are included in this paper to demonstrate that severe loss of gas recovery occurs primarily in low productivity reservoirs. Production data from two wells were history matched with simple radial models to evaluate the potential range of the critical condensate saturation (the minimum mobile condensate saturation) and its impact on gas recovery. Published laboratory data for gas-condensate relative permeability were used as a starting point for these simulations.

The primary conclusion from this study is that productivity impairment results in reductions in gas recovery for wells with a permeability-thickness below 1000 md-ft. The history matched simulations support a range of critical condensate saturations from 10% to 30%, in good agreement with published laboratory values.
Correlations for Liquid Densities and Evolved Gas Specific Gravities for Black Oils During Pressure Depletion
Authors: McCain William D. , Hill Nathan C.
Published: December 2007

Two new correlations are presented. The first correlation can be used to estimate the changes in density of a reservoir oil as reservoir pressure declines and gas evolves from solution. The second correlation can be used to estimate the changes in specific gravity of the gas evolved during the depletion process. Both correlations require normally available field data.
Influence of Temperature, Pressure and Molecular Weight of Hydrocarbon Components on the Multi-Phase Equilibria of Hydrocarbon/Water systems
Authors: Chawla I. S. , Barrufet M. A. , Rahman S. , Beladi M. K. , Wu C. H.
Published: December 2007

We have performed three-phase separation experiments for different multi-component hydrocarbon/water systems for hydrocarbon component varying from C1 to C20. Experiments were done on two different experimental setups. PVT-VLLE apparatus can provide on-line compositional analysis and phase volumes of all phases for temperatures up to 350 °F and Isochoric Steam Distillation Cell (ISDC) can provide only vapor phase compositions, but it can be used up to 500 °F. The experimental results from these cells were compared with results from an equation of state simulator (VLLESIM) and are found to be in excellent agreement. VLLESIM is then used to study the effect of temperature, pressure and molecular weight of hydrocarbon components on multiphase equilibria of different hydrocarbon/water systems.
The Material Balance Approach vs Reservoir Simulation as an Aid to Understanding Reservoir Mechanics
Authors: Ali S.M. Farouq , Nielsen R.F.
Published: December 2007

Recent years have witnessed great strides in reservoir simulation techniques. Numerous reservoir simulators have been developed, and are being employed in comprehensive reservoir production optimization studies. With increased emphasis on total simulation employing mathematical models, one cannot help wondering whether the classical material balance methods are passe. The present article attempts to demonstrate the value of material balance type studies as aids to gaining an understanding of oil reservoir behavior. The generality of the material balance approach is discussed, that is, the employment of a single material balance equation, but in certain prediction calculations, different saturation equations prediction calculations, different saturation equations for different combinations of the basic oil production processes, i.e. gas cap expansion (with production processes, i.e. gas cap expansion (with gravity segregation, with or without counterflow), solution gas drive, and water drive. Limitations of this method, as well as certain complicating features are pointed out. Both integral and differential forms of overall material balances are discussed, and some of the basic characteristics of each, which are often overlooked, are brought out.

The value of the material balance approach vs. numerical simulation is discussed, and the chief advantages of each technique are pointed out using specific examples. It is suggested that the material balance approach, presented with the unified concept proposed here, will continue to be of value in gaining a basic understanding of oil reservoir production processes, and their mutual interactions.

Introduction

The most important development in petroleum engineering during the last decade has been the extensive use of reservoir simulators for simulating complex problems which could not have been solved by conventional material balance methods. The value and the degree of sophistication of such simulators will increase in the years to come. At the same time we believe that the material balance approach will continue to be a valuable tool in gaining an understanding of reservoir mechanics. It is particularly useful as a teaching aid, especially with the unified concept discussed below, which helps to show both its advantages and limitations. The chief objective of the present article is to discuss some of our experiences with teaching advanced reservoir engineering both from the classical and the simulation points of view.
Geologic Properties that Affect Waterflooding in the Big Injun Sand of West Virginia
Authors: Watts Royal J. , Overbey William K.
Published: December 2007

This study was made to determine the petrography, mineralogy, porosity, and petrography, mineralogy, porosity, and permeability of the sandstone, and their permeability of the sandstone, and their relationship to waterflooding in Big Injun reservoirs. Rotary cores, geophysical well logs, petrographic thin sections, and results of chemical analyses of sandstone samples from several Big Injun oil reservoirs were used to determine these parameters. The results show a great range of reservoir characteristics within area of study.

The petrography of the sandstones ranges from lithic graywackes (very shaly), to protoquartzites (clean), with varying mineral protoquartzites (clean), with varying mineral constituents. Porosities and permeabilities also vary greatly due to the petrography and mineralogy of the sandstone. Interstitial clay minerals constitute from less than 5 to more than 25 percent of the reservoir rock. Other important interstitial constituents of the Big Injun sand are secondary precipitated carbonates and quartz. The framework of the Pocono Big Injun sand is composed mainly of Pocono Big Injun sand is composed mainly of quartz grains with minor amounts of rock fragments, heavy minerals, and feldspar.

The interstitial clays and cements in the Big Injun sand have greatly reduced the original porosity and permeability of many of the porosity and permeability of many of the reservoirs studied, and will dictate water-flooding techniques that must be used for successful operations. Laboratory results show that the permeabilities of most Big Injun sands are reduced more than 50 percent by flooding with fresh water as compared with results after flooding with saline water. Several Big Injun sand pilot waterfloods in which fresh surface water was used have been unsuccessful, partly due to low injection rates caused by reduced permeability and pore plugging of the formation. permeability and pore plugging of the formation. Any future Big Injun waterflood projects should use saline formation water in a closed system to reduce interaction between flood waters and the interstitial constituents of the formation.

Introduction

Reserves of premium quality Pennsylvania grade crude oils are steadily being depleted. The refining capacity for Penn grade crudes is increasing and will soon place additional demands on the supply. Much of this additional crude must be produced by secondary-recovery techniques such as waterflooding.

The Bradford area oilfields in Pennsylvania and New York have been successfully waterflooded since 1920.
Virtual Measurement in Pipes: Part 1—Flowing Bottom Hole Pressure Under Multi-Phase Flow and Inclined Wellbore Conditions
Authors: Ternyik J. , Bilgesu H. I. , Mohaghegh S. , Rose D. M.
Published: December 2007

Pressure drop prediction in pipes is an old petroleum engineering problem. There is a long history of attempts to develop empirical correlations to predict the pressure drop in pipes. Some of these attempts have produced correlations that provide good prediction in some cases. However, their general applicability is question-able. Correlations that address only a specific class of problems exist. These types of correlation usually perform better than those which attempt to meet the need of av ariety of problems. Usually, the higher the_ number of variables in the model the lesser the reliability and general applicability of the correlations. This is the result of using methodologies such as conventional regression analysis. In such methodologies, the chances of correctly and completely captwing the relationship between variables decreases as the number of variables increases. Many parameters could be involved in these types of problems, such as gas-oil ratios in two phase systems, water flow in three phase systems, and inclination angles of the pipe, to name a few. In this paper, the authors introduce a new methodology for developing prediction models for pipes. This methodology, which has been named Virtual Measure-ment in Pipes (VMP), incorporates the cutting edge of infmmation technology, artificial neural networks (ANN), to address the development of tools to predict pressure drops in pipes and optimum design of pipelines under a variety of circumstances.

The fimdamental problem with conventional approaches resides in the inherent sequential and point wise (as opposed to parallel and distributed) information processing methods used in development of such correlations. Because of this short coming, conventional methodologies are unable to address, defme, or unravel the highly complex relationships between many variables involved in the process. In this paper, artificial neural networks are used to develop a Virtual Measurement Tool to survey flowing bottom hole pressure in multi-phase systems using information such as oil, gas and water flow rates, temperature, oil and gas gravity, pipe length, swface pressure, and inclination angles of the pipe. The developed Virtual Measurement Tool has been applied to the published field data for flowing BHP predictions. VMP's predictions are com-pared to existing methods and the enhancement is clearly demon-strated.

The developed VMP tool can be applied to wellbore hydraulic problems. It can address three-phase (oil, water, and gas) flow in well bores. This tool applies to a variety of wells, including vertical wells and those with various degrees of inclinations.
Virtual Measurement in Pipes: Part 2-Liquid Holdup and Flow Pattern Correlations
Authors: Ternyik J. , Bilgesu H. I. , Mohaghegh S.
Published: December 2007

The prediction of liquid holdup and multiphase flow regimes present in a well or pipeline is very important to the petroleum industry. Liquid holdup, defined as the fraction of pipe occupied by liquid, and flow regimes must be predicted to design separation equipment and slug catchers in pipeline operations properly. It is also important when designing gas storage fields in depleted oil reservoirs.

A new methodology was developed to model multiphase flow conditions for pipelines and wellbores using only known surface data, This methodology, which has been named Virtual Measurement in Pipes (VMP), incorporates an innovative use of information technology and computational intelligence, to address the development of tools for the engineer to use in the design process for a variety of conditions. Artificial neural networks (ANN) were used to develop a Virtual Measurement Tool to survey the liquid holdup and flow regimes in nonspecific multiphase flow systems using readily available data.

The VMP methodology was tested for validity by comparing virtually measured values with published measurements, As a result, the method proved to be an accurate virtual measuring tool to predict liquid holdup and flow regimes in multiphase flowing pipelines and wellbores, The VMP methodology also demonstrated an enhancement to existing industry recognized correlations.
The Impact of Friction Factor on the Pressure Loss Prediction in Gas Pipelines
Authors: Bilgesu H. Ilkin , Koperna George J.
Published: December 2007

Gas pipeline design is greatly affected by the amount of a pressure drop anticipated during different phases of natural gas transportation. The outlet pressure can be computed by a common gas pipeline equation such as Weymouth or Panhandle formulas at the desired flow rate and pipe size. In addition to selecting the proper size of a pipeline, the compressor capacity and the related cost are determined based on the discharge pressure. The flow rate, in these equations, is defined in terms of a turbulent friction factor. The fiiction factor relationship approximates the turbulent behavior as a :fi.mction of surface roughness in the pipe. An efficiency factor is employed in the equations for adjusting deviations in the pressure drop calculations. Existence of a sub layer, due to the pipe surface condition and accumulations of condensate, can generate cases that cannot be defmed properly by the use a single friction factor. The proper sizing of a pipeline can be improved by defming the ranges of errors introduced with the use of different friction factors.

Different correlations exist for the calculation of the friction factor, f, as a function of Reynold's number and the relative roughness of the pipe. The formulas for f either require an iterative procedure or may be solved explicitly. Also, each friction factor correlation exists with its own valid limits regarding Reynold's number and relative roughness. Thus, some equations are simple to use but not accurate and some are accurate but not easy to incorporate into the fmal equation.

In this study, the effect of the friction factor on the pressure drop calculations for gas flow is presented. Various correlations for friction factors are utilized to demonstrate their impact on the design of natural gas pipelines. Also, a summary and a comparison of results are presented for different flow rates, pipe sizes, and for field data.
A Reservoir Model For Hillsboro Gas Storage Field Management
Authors: Udegbunam Emmanuel O. , Kemppainen Curt , Morgan Jim
Published: December 2007

A three-dimensional (3-D) reservoir model, developed from stratigraphic and petrophysical data, was used to understand the past behavior of the Hillsboro Gas Storage Field and to investigate the field’s performance under various future development. Twenty-two years of the gas storage reservoir history, comprising the initial gas bubble development and seasonal gas injection and production cycles, were examined with a full-field, gas-water, reservoir simulation model. Key issues in storage developments examined after successful history matches of the past gas storage performance included (1) the maximum possible total gas-in-place volume without gas loss and (2) the optimum base load volume that permits the achievement of the peak-day rate requirements.

The results from various simulated development strategies suggest that the gas-water front is already in the vicinity of the west observation well and that increasing the field’s total gas-in-place volume would cause gas to migrate beyond the east, north and west observation wells. They also suggest that storage enlargement through gas injection into the lower layers may not prevent gas migration. Concerning gas deliverability, simulated results suggest that a peak day rate of about 150 Mmscf/D can be achieved with up to 80% of the working gas produced before the peak day and that the peak day rate would fall below 125 Mmscf/D when 85% or more of the working gas is produced before the peak day. Furthermore, the results suggest that. the addition of strategically-located new wells would boost the simulated gas deliverabilities.
Gas-Condensate Production and Allocation Prediction Program
Authors: Gates Charles W. , Hughes Don L.
Published: December 2007

A procedure has been adapted and a computer program prepared to predict the depletion of a predict the depletion of a gas-condensate field, or a system of several fields, and allocate the desired total production between fields and reservoirs. Well capacities at declining reservoir pressures are used to calculate a pressures are used to calculate a reservoir's and a field's capability at any given time. Gas rates are determined quarterly on a wet, separator, and plant sales volume basis. Condensate and NGL production are also calculated. A dummy field option allows the prediction of the Additional reserves needed to sustain a selected sales rate, together with the timing at which they must be added. Additions, deletions, and recompletions of wells may be performed, and additions or deletions performed, and additions or deletions of reservoirs can be handled.

The program provides a tool to (1) determine the future performance of a property for operational purposes, (2) aid in evaluating purposes, (2) aid in evaluating alternate gas producing proposals, and (3) provide faster and more accurate data for economic evaluations.

The basic unit of prediction is the reservoir, with reservoir groupings forming a field, and field groupings forming a complete system. Both full pressure depletion and partial pressure depletion reservoirs can be pressure depletion reservoirs can be handled. The input consists of well deliverability data, reservoir and reserve information, and a forecast of contract demand.
Improvement in the Characterization of the Acid Wormholing by "In Situ" X-Ray CT Visualizations
Authors: Bazin B. , Bieber M.T. , Roque C. , Bouteca M.
Published: December 2007

Introduction

Acidizing of carbonate reservoirs is a widely used process to improve reservoir production. Acid dissolves portions of the rock, making channels; the result is an increase in permeability. Two different stimulation processes deal with acids: matrix acidizing and fracture acidizing While in matrix acidizing deep, highly ramified channels are desirable around the wellbore in fracture acidizing, compact patterns are preferable since they limit fluid loss through the fracture walls and thus increase acid efficiency. A large number of studies deals with acidizing patterns. Core observations after lab experiments consist in most cases in replica of the acid etched channels by filling the channels with resins or melting-point alloys and dissolving the surrounding rock material. Compact patterns, wormholes of limited size, highly branched wormholes, i.e. trees like patterns have been observed with this technique. Also, very pitted core faces have been mentioned. On another hand, modeling studies try to reproduce the pattern observed. Network models show tree like pattern. Capillary models put forward the dissolution mechanisms and the determinant effect of the acid filtration from the wormhole wall on the acid propagation. However, the way of formation of these facies and the different parameters influences on the pattern size are not clearly established.

Mechanisms involved in carbonate dissolution by acids depend on the nature of the chemical reaction and on the flowrate. For limestone, the dissolution is mass-transfer limited. For this material, the acid flowrate has a determinant effect on the acid propagation rate defined as the ratio of the core length to the acid breakthrough time. At low flow rate the dissolution is compact and no wormhole forms; at high flowrate, the dissolution is mass-transfer limited: it is the wormholing regime;

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Underbalance or Extreme Overbalance
Authors: Behrmann L. A. , McDonald B.
Published: December 2007

Application of an extreme overbalance, sufficient to fracture the reservoir formation, applied either during or after perforating was first presented as an alternate completion technique during the 1993 Fall SPE Conference1. During the ensuing two years, a number of jobs have been run by different operators in a variety of formations with varying applications. The primary question asked by an operator relates to the benefit of Extreme Overbalance (EOB) versus current perforation techniques of underbalance (UB) or modest overbalance for well control. Of course this question spawns a whole set of new questions about when and how to use and the benefits and risks of the EOB. EOB, as used in this paper, includes Extreme Overbalance Perforting (EOP) and Rapid Overpressured Perforation Extension (ROPE).

This paper compares and contrasts UB and EOB strengths and weaknesses and provides recommendations of when and why to use the different techniques. Field examples are provided of successful and unsuccessful application of EOB completions.
Formation Damage Removal Through the Application of Enzyme Breaker Technology
Authors: Moore W. R. , Beall B. B. , Ali Syed A.
Published: December 2007

This paper describes laboratory experiments demonstrating that the use of polymer linkage specific enzymes is effective in breaking the starch polymer constituent of sized salt fluid loss control materials (FLCMs). It is further demonstrated that the linkage specific enzymes are efficient in reducing the near-wellbore damage induced by the starch polymer that makes up roughly 75% of the FLCMs polymer content. As a result of the laboratory work presented here, it is shown that return permeabilities arc in the 8098% range without the use of acid systems.
Selection of Screen Slot Width to Prevent Plugging and Sand Production
Authors: Markestad P. , Christie O. , Espedal Aa. , Rørvik O.
Published: December 2007

A numerical model has been developed that addresses both plugging of, and sand production through single wrapped screens. The model was developed on the basis of a fractal model for the particle size distribution of reservoir sands. A database of sand types from the North Sea and Haltenbanken areas was established. Principal component analysis was used to reduce the number of significant variables in the database, and to provide a basis for a prediction model for critical slot widths. A series of laboratory experiments were performed, and four critical slot widths were identified for each sand type, defining a safe design interval for screen slot width. A mathematical model was developed that can be used to predict the critical slot widths for other sand types from the area.
Gravel Pack Procedures for Productivity and Longevity
Authors: Barrilleaux M. F. , Ratterman E. E. , Penberthy W. L.
Published: December 2007

The primary objectives of a gravel pack are preventing formation sand production, achieving high productivity, and providing completion longevity. For cased hole completions, inadequately filling the perforation tunnels with gravel is probably the main cause of formation damage which ultimately translates into a well that is completion limited since it produces below the capacity of the reservoir. Hence, performing prepacking operations that fill the perforations with undamaged gravel will usually enhance productivity. Aside from prepacking, effectively packing the casing-tubing annulus produces a stable, void-free gravel pack that will not settle or deteriorate with time.

Gravel pack procedures were developed in the mid-1970's and subsequently optimized to address the above concerns. They consisted of preacidizing (if required) the formation followed by a prepack performed with lightly-gelled water pumped at matrix rates that filled the casing with gravel to the top of the perforations. After washing the prepack gravel from the casing, the gravel pack assembly was run and an annular gravel pack was performed using water as the transport fluid. This procedure provided two opportunities for gravel to prepack the perforations. Acidizing was subsequently performed to achieve the desired productivity. Well test data show that over 70% of the wells tested had skin factors that were less than 10 and many were in the zero range. Gravel pack failures were rare and over 95% of these completions produced to depletion without requiring a workover.

More recently, enhanced prepacking has been performed by pumping at high rates and using water as the transport fluid. These treatments were designed to fracture the formation a distance of 5-10 ft from the well to bypass formation damage. The high rate prepacks have been performed with either the screen in place (single step) or prior to running the screen (two-step) in the well. In either case, the annular pack continued to be performed with water. The high rate completions have been performed at little or no incremental cost compared to those conducted at matrix rates since they were performed with platform-based, moderate horsepower equipment. The performance of these completions has been excellent. The need for postcompletion acidizing and associated flowback concerns has been virtually eliminated. Wells clean up more rapidly, consistently have higher productivities, and appear to have improved completion success as compared to those performed at matrix rates.
Evaluating Completion Damage in High Rate, Gravel Packed Wells
Authors: Burton R. C. , MacKinlay W. M. , Hodge R. M. , Landrum W. R.
Published: December 2007

Conoco has completed and tested a series of high rate, gravel-packed oil wells. Analysis of the well test data for the first completion indicated significant formation/completion damage had been caused during the gravel-packing process. Extensive laboratory testing designed to closely simulate the completion procedure was performed in conjunction with detailed completion pressure loss evaluation. The studies identified the LCM pill used during completion operations as the primary source of damage. A new. self-breaking, LCM composition was designed that provided fluid-loss control with minimum formation/completion damage. This LCM system and a number of other design improvements were then used in the field's remaining gravel-packed completions.

This paper describes the analysis of well test data and the application of this information to evaluate completion procedures for these high rate, cased-hole, gravel-packed completions. The analysis technique used is unique in that it uses a combination of laboratory, analytical, and operational data to quantify individual components of the total measured pressure drop across the completion. This approach provides a significantly better insight into completion performance than merely stating an overall completion pressure drop, skin value, or well flow efficiency.

This systematic analysis of pressure losses resulted in a better understanding of "formation damage" effects and the factors that influenced them during the completion process. This in turn allowed completion procedures to be modified to target specific areas for improvement.
Diversification In The Petroleum Industry: Pros And Cons
Authors: Kennedy Edwin L.
Published: December 2007

1962 AIME Annual Meeting, Los Angeles, CA, October 7–10, 1962

In recent years much has been written in the trade journals of oil about the upheaval that has beset this industry, its causes and its correction. And it is likely that considerable more has been written by stockholders in oil to corporate managements that has not been published, as these stockholders witnessed a progressive decline in the relative ranking of the industry's securities by investors during the past five years. Words dear and intriguing to the market letter writers, such as glamour, growth, compound rate of gain, new products, obsolescence arising from research, etc., have largely escaped application to the securities of this basic industry. Even the phrase "relatively attractive" has appeared infrequently and then usually only after a significant decline in prices of the industry's equities.

Producing Companies Disappear

We shall not pause to examine the causes of oil's decline from its previous place of esteem nor to prescribe remedial measures nor even to guess as to the future.
Use of a Viscoelastic Carrier Fluid in Frac-Pack Applications
Authors: Brown J. Ernest , King Lee R. , Nelson Erik B. , Ali Syed A.
Published: December 2007

The fluids commonly used in frac-pack treatments were initially designed for either fractruing low permeability formations or for conventional gravel pack operations. These fluids do not address the unique problems found when fracturing higher permeability formations. Conventional frac-pack fluids (borate crosslinked guars and HEC) undergo whole polymer leakoff, and create a deep invasion bank of concentrated polymer that is very difficult to break and can lead to high formation damage.

Viscoelastic surfactant (VES) fracturing fluids have been developed which exhibit excellent rheological properties and still maintain low formation damage characteristics even in high permeability formations. These fluids are completely polymer free and do not rely on internal chemical breakers to degrade the fluid viscosity.

This paper will detail the results of recent laboratory studies on viscoelasitic surfactant fracturing fluids, and will compare the rheological and formation damage properties to other conventional fracturing fluids. The laboratory findings will be substantiated by several field case studies.
The Correct Selection and Application Methods for Adsorption and Precipitation Scale Inhibitors for Squeeze Treatments in North Sea Oilfields
Authors: Jordan M. M. , Sorbie K. S. , Graham G. M. , Taylor K. , Hourston K. E. , Hennessey S.
Published: December 2007

Over the past three years, the Oilfield Scale Research Group at Heriot-Watt has conducted a number field studies to evaluated scale inhibitors for both downhole squeeze application and topside continuous injection for a number of North Sea operating companies. This paper presents an approach for screening commercial sulphate and carbonate scale inhibitors for field application. The screening results, which include data from static/dynamic inhibitor efficiency, static adsorption, compatibility and thermal stability are used to rank the performance of commercial scale inhibitors. From this short list, a small number (1 to 3) candidate products are taken on to reservoir condition coreflooding. In the screening of topside scale inhibitors, no adsorption tests are conducted.

Results from adsorption and precipitation type corefloods will be compared for polymer and phosphonate chemistries selected using these screening procedures. Such corefloods serve both to evaluate the squeeze lifetime performance and to assess the levels of formation damage caused by the scale inhibitor package. The strategy of deriving a dynamic isotherm which can be utilised in computer modelling of the coreflood data to produce a "Field Squeeze Strategy" will be outlined. This systematic approach provides a set of effective and economical methods for the chemical screening of scale inhibitors. This results in an improved field application strategy with longer squeeze lifetimes, while minimising formation damage potential.
Energy Supplies in the 1970's: Abundance vs Scarcity -- The Issue of Prices
Authors: Steele Henry
Published: December 2007

Introduction

In the past, the energy consumer in the United States in peacetime has faced no genuinely inconveniencing shortages of energy supplies. On the contrary, fuels have generally been abundant. But recently there has been much concern expressed in regard to prospective shortages of major energy sources. Fears were earlier voiced concerning an impending shortage of natural gas, and there are many who foresee declining supplies in the future, which will leave an increasing deficit for gas needs in view of the rapidly rising trends being projected for demand. And although some excess projected for demand. And although some excess producing capacity exists currently for crude producing capacity exists currently for crude oil, the level is apparently declining and in any event when realistically estimated compares unfavorably with volumes of imported oil. Furthermore, proved reserves of oil have been declining for several years, and trends in new discoveries per unit of exploratory effort have remained at disappointingly low levels for over a decade. More recently, concern has been registered in regard to coal supply, as some buyers have experienced difficulties in meeting their requirements.

Until recently, concern over impending energy shortages was limited largely to those who were immediately affected by them. But the number so affected was increased sharply by the severing of the Aramco Tapline in May 1970, and the sudden major restriction of crude oil output ordered by Libya the following month. These two actions, which reduced oil availability by over a million barrels per day, brought to the attention of many energy consumers the degree of precariousness in the energy supply equilibrium currently established.

IMPLICATIONS ON ENERGY SUPPLY

These actions however, are only the most highly visible factors in a pattern of developing supply shortages, and serve primarily to throw into sharper focus the somewhat longer run implications for energy supplies of a combination of economic forces and administrative actions which have created latent scarcities of several important fuels.
Model Wellbore Evaluation of Diverter Effectiveness Confirmed by Field Results
Authors: Morgenthaler L. N. , Burnett D. B. , Kiel V. D.
Published: December 2007

Effective diversion is critical to successful stimulation of long-interval, high-rate wells. Once near-wellbore damage has been removed in one portion of the completion interval, steps must be taken to divert stimulation fluids to intervals that remain damaged. Viscous fluid diverters, such as gels, foams, and emulsions, have all been used with success in field applications. These three diverter types were compared in the Westport Technology Center wellbore model. Foams and emulsions were found to provide more effective diversion than gel.

Based on the laboratory results, foam diversion was used during stimulation of injection wells at Shell Offshore Inc.'s Bullwinkle platform. Comparison of diverted and undiverted treatments quantifies the benefits to be gained from effective diversion and demonstrates that wellbore model studies correlate well with field results.