bluuebunny/crossref_metadata_2025 huggingface dataset:
Pilot Waterflood Evaluation - Panhandle Field
Authors: Henry J.C. , Moring J.D.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers, Inc.

This paper was prepared for the Society of Petroleum Engineers of AIME, Regional Secondary Recovery Symposium, to be held in Pampa, Tex., Oct. 26–27, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copies. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

In July, 1963, a five-spot pilot water-flood was initiated in the Brown Dolomite of Skelly Oil Company's Schafer Ranch lease in the Panhandle Field, Carson County, Texas.

Two years later response had not yet occurred even though 1,300,000 barrels of water had been injected. Injectivity surveys indicated that the water was entering the producing formation at the well bore but what happened to it after that remained a mystery.

A decision was made to find out if the water was actually staying in the formation. This was to be done by drilling a test well half way between one of the four injection wells and the center production well.

Analysis of test data indicated that the advance portion of the flood front had already passed this position and must be close to the center producing well. The flood was behaving admirably - water was going into the formation and not channeling. Fracture treatment of the center producing well resulted in the long-awaited response.

Introduction

This paper is about an evaluation of a pilot waterflood. However, it is not a theoretical evaluation based on hypothetical data. It is based on actually drilling a well in the middle of a pilot, coring, logging and testing it, and then analyzing this data. We did what many of us that try to deal in abstract reservoir engineering would love to do. In effect, we went down and took a chunk out of the reservoir while it was in the process of being flooded.

PANHANDLE FIELD

The pilot (Figure 1) is located in the Texas Panhandle Field: the second largest field in terms of cumulative production in the United States. Only the East Texas Field is larger, with a cumulative production of 3.7 billion barrels compared to the Panhandle Field's 1.2 billion barrels. This field is over 100 miles long and extends into five counties. Just to the south of the field is a buried granite mountain ridge, called the Amarillo Mountains, which extends into Oklahoma where it becomes the Wichita Mountains.
Fully Computerized BHA Analysis Significantly Improves Directional Drilling Performance
Authors: Gibson M. T.
Published: December 2007

Texaco North Sea UK Co significantly improved directional drilling performance on their recent ‘S’ shaped Highlander development well by utilising four specialised computer programmes.

By analysing the performance of every past BHA run on previous Highlander directional wells, it was possible to design idealised assemblies prior to spudding the well. The in-field performance of the designed BHA's was then optimised by use of an on-site computer system.
Upgraded Semisubmersible Drilling Rigs Set a New North Sea Standard
Authors: Bearne M. C.
Published: December 2007

Two heavy duty North Sea semi-submersible drilling units have been enhanced by the installation of additional buoyancy chambers and upgraded drilling equipment. This relatively recent investment in the rigs has improved drilling performance. It also means that the future challenge of an increasingly demanding North Sea exploration programme can be tackled with both confidence and vigour.
Enhanced Oil Recovery by Wet In-Situ Oxygen Combustion: Esperson Dome Field, Liberty County, Texas
Authors: Pebdani F. N. , Longoria R. , Wilkerson D. N. , Venkatesan V. N.
Published: December 2007

A field test of wet in-situ oxygen combustion has been carried out in the Esperson Dome field in southeast Texas. The objectives of the pilot test were to evaluate the potential of oxygen combustion technology, to assess its advantages over air fireflooding, and to gain experience in the safe handling and downhole injection of high purity oxygen in an oil field environment.

The Miocene sandstone chosen for the pilot is relatively deep (2700 feet), thin (20 feet), and had been substantially watered-out by a strong natural water drive. At the beginning of the combustion pilot an estimated 850 bbl/acre-ft (36% saturation) of 90 cp (21 °API) oil remained in place. The natural water drive dominated the combustion process and assisted in displacing the oil. At project termination, 200 MMscf of oxygen and 55 MMscf of nitrogen had been injected, 90,000 barrels of oil recovered, four existing older wells failed, four new wells drilled, and three wells burned out. Determination of incremental oil is uncertain due to these operational changes.

The objectives of the project were met, and improvements in the project design and operation are expected to lead to an economic process for further applications.
Two-Phase Flow Through Porous Media: Effect of an Adsorbed Polymer Layer
Authors: Zaitoun A. , Kohler N.
Published: December 2007

Polyacrylamide and polysaccharide adsorption on natural water-wet sand and sandstones is shown to modify markedly the flow behavior of both water and oil. At residual oil saturation, the quantity of adsorbed polymer per gram of rock is found to be almost the same as at full water saturation, but the permeability reduction to water is increased by the presence of trapped oil droplets which reduce the flow cross-section for the water phase. The presence of adsorbed polymer always induces an increase in the water irreducible saturation due to polymer hydration water which is not expelled by contact with oil. However the oil relative permeability is shown to be little affected by adsorbed polymer over the remaining saturation range. On the basis of a capillary two-phase flow model, this phenomenon is interpreted as the result of the competition between the reduction of flow cross-sections and the enhancement of the water-wettability of the rock, with both effects having the same origin, i.e. the polymer adsorption process.
The Influence of Rheological Properties on Mobility Control in Polymer-Augmented Waterflooding
Authors: Allen E. , Boger D. V.
Published: December 2007

One of the major restrictions to increased oil recovery from reservoirs is poor sweep efficiency, caused by an interfacial instability phenomenon termed "viscous fingering". This paper reports the results of an experimental study into viscous fingering in two-phase flow, using a one metre diameter Hele-Shaw cell. Newtonian and non-Newtonian fluids were tested, including shear-thinning and ideal elastic (Boger) fluids. The viscous fingering patterns exhibit fractal behaviour, which enable both characterisation of the displacement pattern and extrapolation to larger scales.

Rheological properties can have a significant influence on the viscous fingering pattern and thus on sweep efficiency. Shear-thinning fluids exhibit significantly increased interfacial instability, especially at the rear interface with the chasing waterflood. Elastic properties have a negligible effect on the macroscale development of viscous fingers, but may have an important role at the microscale, by modifying the viscosity ratio for flow in porous media. Results to date suggest that the greatest improvement in sweep efficiency for EOR polymer flooding may result from the development of a pusher fluid with viscoelastic non-shear-thinning properties.
An Analysis, Of Single Point Entry And Fracture Plane Control
Authors: Clark Roscoe C. , Bucy B.J.
Published: December 2007

PUBLICATION RIGHTS RESERVED

This paper is to be presented at the 36th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in Dallas October 8–11, 1961, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

"Single point entry" is rapidly becoming a conventional well completion technique when a well is to be stimulated by hydraulic fracturing. Along with this, the concept of "control of fracture planes" is becoming acceptable. As a practical matter, the two concepts are almost inseparable.

For years we have searched for ways and means for controlling oil reservoirs (i. e. getting them to produce oil the way we want them to). Hydraulic fracturing, and more particularly, CONTROLLED hydraulic fracturing, is a good long stride in this direction.

There is little argument against the two concepts. Considerable well data supports the desirability of creating as much fracture AREA AWAY from the well bore as possible and as much fracture CONDUCTIVITY as possible near the well bore. Statistical data now substantially supports that fractures can be controlled to the plane de sired a high percentage of the time - possibly as high as 75%. Skeptics of controlled fracture planes, however, have little to lose if they do believe in the advantages of single point entry. The worst failure that can be expected from attempted fracture plane control is simply an uncontrolled fracture. This result is assured if no attempt is made to control the fracture plane.

Single point entry completions offer the following substantial advantages:Greatly minimizes the chances for communication between zones. This is due to the longest amount of blank space possible between perforated intervals. Also, laboratory and field data collaborate in indicating that many cases of communication are caused by initiation of vertical fractures. These may occur up the cement column and/or in the formation adjacent to the bore hole.Excellent opportunity to retain all the fracture area in the producing zones.
Economic Factors Controlling Drilling Activity
Authors: Woods T. J.
Published: December 2007

Over the past 40 years, U.S. drilling activity has fluctuated substantially. Over this period there have been some significant changes in price or in U.S. energy policy to prevent or allow price changes. As a result, a substantial body of theory has grown up to relate oil and gas prices to drilling activity.

However, a detailed analysis of drilling activity indicates that price, while important, often serves only as a proxy for the economic factors that actually affect industry activity. Energy policies regulating price, such as the Phillips decision regulating the wellhead gas price in interstate markets, have shown limited impacts on drilling activity. Regulations or market conditions affecting oil and gas production rates, however, have significantly affected drilling activity.

This paper assesses the periods in the past when there were significant changes in the level of industry activity to investigate the role that price has played in industry decisions. The analysis will consider periods during which activity has expanded and periods during which activity has declined. The analysis indicates that cash flow plus profitability, not price, dominate the industry's decisions. Thus, the mere increase or decrease in price is not sufficient to cause substantial changes in industry activity.
The Effect of Uncertainty in Petroleum Reserves Estimates on Hotelling's Economics of Exhaustible Resources
Authors: Stultz-Karim Sharon P. , Economides Michael J.
Published: December 2007

The economics of exhaustible resources was employed in this paper to isolate the relationships between reserves estimates, time, and optimal pricing. A multilinear regressive technique was utilized to evaluate the statistical significance of the relationship of the independent variables of uncertainty in reserves estimates and time to the dependent variable of price. An idealized model of the international petroleum market was used as the basis of analysis and to develop theoretical statements regarding the affect of uncertainty in reserves estimates on petroleum pricing.

It was found that for reserves estimates made with uncertainty there was a statistical significance in its effect on pricing through time while reserves estimates made with certainty only time had a significant effect on pricing. Therefore, static commodity-based equilibrium methods of economic analysis are not adequate for the forecasting of future petroleum prices. Instead, price forecasting models must be dynamic and must incorporate reserves estimates that have been calculated with the most precise reservoir engineering and geological methodologies.
The Replacement Costs of Domestic Crude Oil and Natural Gas Reserves
Authors: Kuuskraa V. A. , Godec M. L.
Published: December 2007

The costs of replacing domestic oil and gas reserves are today dramatically different than during the "boom" years of the early 1980s. Changes in costs, tax laws, and drilling efficiency have altered the outlook for oil and gas and thus have fundamentally revised least-cost supply strategies.

To provide a perspective on the new outlook, it is timely to re-examine the economics of finding and producing domestic oil and gas reserves. For this, the paper reviews recent data on domestic oil and gas expenditures, reserve additions, drilling costs and supply sources. The paper also examines the response of drilling costs to changes in oil prices, rig utilization, and technology.

The paper illustrates that least-cost reserve replacement will consider a supply portfolio that includes at least six sources: (1) undiscovered conventional oil and gas, (2) reserve growth from infill drilling, (3) oil (and particularly gas) from the deepwater OCS, (4) natural gas from low permeability sources (tight sands, coal seams and Devonian age shales), (5) enhanced recovery of heavy and light oil, and (6) expanded development of the North Slope of Alaska. Specific case studies of coalbed methane development in the Warrior Basin, infill drilling in the Permian Basin, and heavy oil steamflooding in the San Joaquin Basin provide examples of how various companies are pursuing their individual strategies.
Single Well Pressure Transient Testing in Prudhoe Bay, Alaska
Authors: Lockhart D. L. , Ogbe D. O. , Dehghani K.
Published: December 2007

This paper presents the results of the application of a mixed-boundary pressure transient testing model to Prudhoe Bay wells. The proposed model considers a constant pressure upper boundary and a no-flow lower boundary. Reservoir anisotropy and partial penetration were considered in the model. These boundary conditions simulate the pressure transient testing in the Prudhoe Bay unit of the Alaskan North Slope where the oil column of the Sadlerochit formation is overlain by a huge gas cap.

A set of type curves for gas cap dominated data analysis is presented. These type curves should complement those presented by Kuchuk and Kirwan for no-flow upper and lower boundaries. A correlation for predicting the beginning of the constant pressure boundary effect is provided. This correlation can be used to estimate the period to record analyzeable early-time data during the design of a pressure transient test. Also, it is a useful tool for validating the results of type curve analysis of data obtained from gas cap dominated transient tests.

Examples of pressure buildup tests conducted in the Western half of the Prudhoe Bay unit are analyzed. The results obtained are used to discuss the problems of single well pressure transient analysis in gas cap dominated reservoirs.
Economics of Hydrocarbon Reserves in Overpressured Reservoirs below 18,000 ft in South Louisiana
Authors: Fertl Walter H. , Leach W. G.
Published: December 2007

Abnormally high formation pressures, generally prevalent in south Louisiana at depths below 18,000 ft, significantly affect reservoir quality, magnitude of reserves, production characteristics and, hence, the ultimate recovery of those deep hydrocarbon resources.

At the time of this study, 515 south Louisiana wells had been drilled below 18,000 ft to Miocene and Oligocene target zones. Seventy-six wells, located in eight coastal parishes, were completed below 18,000 ft. A total of 146 wells were drilled as dry holes, in conjunction with these 76 completions, either on the same geological structure or in the same field. Of these 146 wells, 65 were dry holes and 81 had dry-hole footage below 18,000 ft. These 222 wells were selected as the basis for the economic evaluation.

The present investigation (1) relates formation temperature and pore pressure to the occurrence and recovery of oil and gas reserves, (2) discusses effects of porosity, permeability, irreducible water saturation, and gas compressibility, (3) illustrates the effects of overpressure on production behavior, depletion, final abandonment pressure, and ultimate recovery, and (4) presents the economical criteria in this deep-well environment.

Based on the above considerations, the resulting economical findings were statistically correlated to the well log-derived shale resistivity ratio (SRR). The SRR value is defined as the ratio of the predicted "normal" shale resistivity divided by the observed, "actual" shale resistivity.

In the present 222-well study, the probability of payout for a well is reduced by 80%, once the SRR exceeds 3.5. Concurrently, the chance of finding greater than one billion ft3 of equivalent-gas is also decreased by 80% once the SRR reaches 3.5. Statistically then, the SRR value, when applied to wells below 18,000ft in south Louisiana, can be used as an important input parameter for economic, managerial decision making. Such decisions may be made on whether to continue drilling, or reevaluate the entire deep drilling program in the geological area.

Field case examples, in-depth discussion of the various parameters, and a detailed review of all significant statistical results are presented.
The Use and Limitations of the Gamma Ray Spectroscopy Tool in a Middle East Carbonate Reservoir
Authors: Berta D. , Vermeulen C. C. L
Published: December 2007

Several carbon/oxygen logs were run in many wells in a producing field to monitor fluid movement. The logs were run at the same time as a detailed reservoir engineering study was being performed, and this paper presents the most important conclusions.

Using the logs from a single well, and published information, the accuracy of the interpreted oil saturations was calculated as 23 saturation units (s.u.) at 20% porosity. The accuracy improves with increasing porosity.

The carbon/oxygen log's depth of investigation is not much farther than the borehole wall, in the area usually flushed by mud filtrate. Field evidence is shown to support the conclusion that interpreted oil saturations are often equivalent to flushed zone saturations calculated from shallow reading microresistivity devices. Evidence is also presented to show that mud filtrate has remained around the wellbore for as long as 30 years. As a consequence, the carbon/oxygen log is thought to have limited applicability in low permeability highly stratified reservoirs.
Outcrop-Derived Quantitative Models of Permeability Heterogeneity for Genetically Different Sand Bodies
Authors: Lewis J. J. M.
Published: December 2007

Core based reservoir data is insufficient in most cases for the accurate prediction and quantification of reservoir heterogeneity. In order to understand the scales and magnitudes of reservoir heterogeneity developed within specific reservoirs, we need to quantify reservoir heterogeneities in large two- and preferably three-dimensionally exposed outcrops of analogous sediments. Variations in depositional architecture are the main cause of reservoir heterogeneity and such variations can be hierarchically classified into a limited number of scales. This hierarchical classification can then be used as a framework with which to quantify reservoir heterogeneities in the field. To apply the data we derive at outcrop to actual reservoirs, we can adopt the sediment-body as the basic reservoir "building block". These building blocks are quantitative models of the scales and degrees of reservoir heterogeneity developed in genetic sediment-body types. Being genetically based, they are widely applicable and not reservoir specific. Seven such quantitative models are being constructed for sand-bodies within carbonate sand depositional environments. Permeability anisotropy can also be considered at a number of depositional scales and it is important to incorporate the correct scale of permeability anisotropy in reservoir simulation grid blocks.
Coring-lnduced Fractures: Indicators of Hydraulic Fracture Propagation in a Naturally Fractured Reservoir
Authors: Laubach S. E. , Monson E. R.
Published: December 2007

Efficient hydraulic fracture treatment of low-permeability reservoirs depends on reliable prediction of the stimulation fracture strike, which generally is parallel to the maximum horizontal stress. Coring-induced fractures can be used to predict the strike of stimulation fractures if coring-induced fractures are aligned with the maximum horizontal stress. Our study (1) determines the orientation of coring-induced fractures in East Texas and (2) compares the strike of coring-induced fractures to indicators of stress direction and stimulation fracture strike. We used descriptions of 565 fractures in 1,802 ft (549 m) of core from seven wells in the Lower Cretaceous Travis Peak Formation, a low-permeability sandstone and shale unit approximately 2,000 ft (609 m) thick that produces gas in much of East Texas. Fracture imaging logs were available from three study wells. Stimulation fracture azimuth was independently determined by monitoring microseismicity during fracture treatment. Mean strike of coring-induced petal and petal-centerline fractures is parallel to the east-northeast azimuth of maximum horizontal stress determined from core strain recovery, borehole breakouts, and strike of fractures created in stress tests and hydraulic fracture treatments. Natural and coring-induced fractures are not parallel, but the difference in strike is generally small (<10 degrees). Petal and petal-centerline fractures are useful for predicting the strike of stimulation fractures. Their usefulness is limited by the precision of core orientation methods.
Acoustic Emission Interpretation for Estimating Hydraulic Fracture Extent: Laboratory and Field Studies
Authors: Sarda J-P. , Perreau P. J. , Deflandre J-P.
Published: December 2007

It is useful to map hydraulic fractures in order to improve the rate of success of such operations and to optimize the pattern of stimulated wells. The proposed method can be used during a minifracturing or prefracturing operation and necessitates a downhole 3D acoustic detector clamped in the well. A few to a few dozen cubic meters of gel are injected during fracturing phases, and the acoustic activity is recorded after every injection. Then signals containing apparent P and S waves are analyzed to determine the directions and distances of the emitting sources. A number of arrivals cannot be interpreted easily, in particular those corresponding to refractions along the casing. Three field examples corresponding to a vertical, a deviated and a slant well are given. Knowing the P and S wave velocities in the different layers and a careful choice of the tool position are essential to the success of the method.
An Assessment of Borehole Seismic Fracture Diagnostics
Authors: Thome B. J. , Morris H. E.
Published: December 2007

A five year effort to apply triaxial borehole seismometer technology to mapping hydraulic fractures by detecting microseismic events associated with the fracturing process has been completed. During this time, a number of evolutionary improvements to the borehole receiver have lead to a unique sensor array geometry consisting of four geophone axes, positioned so that each axis makes the same angle with both the horizontal plane and the plane of the clamp arm. This geometry is designed to allow the use of identical geophones on all axes in order to avoid differences in resonance properties of horizontal and vertical geophones, and to distribute any effects of clamp arm resonance uniformly to all axes. Each axis consists of four geophones wired in series to provide four times the sensitivity of a single geophone.

The receiver includes downhole amplifiers which provides two gains, 112 dB for weak seismic sources and 100 dB to avoid saturation from strong seismic sources. The amplified seismic signals from the eight data channels are frequency division multiplexed onto frequency modulation subcarriers for transmission to the surface through a single conductor wire line. This combination of multigeophone reception, downhole amplification and frequency modulation data transmission results in a very sensitive receiver, almost completely free of electric noise. The data from two downhole receivers in offset wells are recorded on tape to provide a continuous record of all signals. Simultaneously, all channels are demodulated, filtered and sent to a signal analyzer which triggers analog-to-digital conversion when any channel exceeds a preset voltage.

An event location scheme, based on primary wave polarization and using directional statistics, computes the location of microseismic events with error estimates. Over 700 microseismic events were digitized during a recent stimulation experiment. Analysis of these data resulted in 160 microseismic event locations, some as far as 450 ft (137 m) from the receiver. The azimuth determined from event locations agrees reasonably well with the predicted fracture azimuth, the head agrees with temperature log tops, and fracture height is in good agreement with fracture model calculations. Wing lengths are less than fracture model predictions unless fracture width is larger than expected.
Effects of Flow Regimes on Production Logging Instruments' Responses
Authors: Roesner R. E. , LeBlanc A. J. , Davarzani M. J.
Published: December 2007

Production logging instruments' responses in multiphase flow wells are frequently confusing due to the effects of various parameters. An important parameter is the type of flow regime encountered during the survey Special knowledge of the flow pattern is necessary if a meaningful analysis of the data is to be made. Some of the parameters affecting the flow regime are flow rate of each phase, pipe diameter, and wellbore deviation angle.

Wells often produce a concurrent flow consisting of two or three phases. Due to different fluid properties between phases, more than one flow regime might be encountered in a survey depth interval. The cause of this transition from one flow regime to another is due in part to an increase in fluid velocity. This increase may be caused by additional fluid entering the well from perforations or from expansion due to pressure changes as the fluid moves upward through the well.

The sensitivities and operating ranges of selected production logging instruments were studied by subjecting them to different parameters that directly affect the flow regime and the instruments' responses. The logging instruments selected for testing were divided into two categories: Row rate and fluid composition.

Examples are presented that demonstrate how a slight deviation angle or an increase in flow velocity alters water fallback, holdup, and the instrument's response. Typical applications of production logging instruments are described with emphasis placed on the effects of two-phase flow. After characteristics of particular flow regimes have been developed, guidelines for instrument selection, data acquisition methods, and log quality control are given.
Reproducible Rheological Measurements on Crosslinked Fracturing Fluids
Authors: Prud’homme R. K. , Ellis S. , Constien V. G. , Knoll S.
Published: December 2007

Reproducible rheological measurements on crosslinked fracturing fluids are necessary to design fracturing operations and to evaluate crosslinked gel formulations. We present the results of cooperative tests on identical gel formulations (HPG polymers crosslinked with titanate and zirconate crosslinkers) run using different rheological instruments: Fann 50C, Rheometrics Pressure Rheometer, and a reciprocating capillary viscometer. With attention to "dynamic mixing", temperature history, shear history during crosslinking, and flow field uniformity, it is possible to obtain comparable data from all three instruments. This has not been possible previously. The effects of temperature and shear history on the evolution of gel rheology is shown to demonstrate how these variables affect the reproducibility of measurements. Experiments on "fast" and "delayed" crosslinking systems show that delaying crosslinking until after exposure to high shear increases the viscosity of the gel.
Oil/Water Emulsions for Pipeline Transport of Viscous Crude Oils
Authors: Pilehvari A. , Saadevandi B. , Halvaci M. , Clark P. E.
Published: December 2007

Heavy (viscous) crude oils have become an increasingly important source of hydrocarbons in many parts of the world. Transport of these viscous crudes from the source to the refinery can be a problem. In a number of producing areas, a pipeline is in place, but the line was designed for lighter (less viscous) crudes. Pipeline transport can be effected by heating, dilution with lighter fractions, or thermal viscosity breaking. All of these techniques are expensive and are not practical in many situations. Techniques are needed to reduce the pumping costs without significantly increasing the handling costs at: either end of the pipeline.

High oil content oil-in-water emulsions have been shown to be a viable alternative to the techniques mentioned above. Dramatic decreases in viscosity can be achieved while transporting a fluid which has an oil content of 70% or greater. A knowledge of the rheological behavior of these emulsions, under both laboratory and field conditions, is important.

In this study, four different viscous crude oils were used. The viscosities ranged between 2000 and 500,000 (estimated) centipoise (2.0 to 500 Pa·s). The emulsions ranged from 60 to 72.5% oil in tap water stabilized with an emulsion stabilizer.

Rheological measurements were carried out with a tube flow viscometer equipped with three tube sizes and a concentric cylinder viscometer (Rheometrics Pressure Rheometer). The data obtained showed that the shear stress-shear rate behavior of the emulsions are highly dependent on oil droplet size. For a given oil concentration, the non-Newtonian character and the apparent viscosity increased with decreasing droplet size. The majority of the emulsions showed shear thinning behavior at low shear rates (below 50 s−1) and Newtonian behavior at shear rates above 1000 s−1.

These data show that the power law model is insufficient for the whole range of shear rates. A three parameter model needs to be considered. Results show that oil droplet size is the dominant factor in the behavior of emulsions. The influence of mixing intensity and duration while preparing the emulsion and emulsifier concentration on the resulting droplet size were investigated. Pipe flow data were collected for scale-up studies. Data were collected in both the laminar and turbulent flow regimes. This study reveals that careful laboratory testing and scale-up is needed prior to the designing of pipeline systems for the transport of heavy crude oils as emulsions.
Carbonate Stimulation Optimization Using Hydraulic Fracturing Field Testing
Authors: Huckabee P. T.
Published: December 2007

Stimulation designs of the Wasson San Andres dolomite have been optimized at the Bennett Ranch Unit through the use of hydraulic fracturing field tests. In-situ measurements of fluid leak-off, vertical distribution of minimum horizontal stress, and fracture propagation overpressures are incorporated into routine stimulation designs of this West Texas carbonate. This "state of the art" design procedure has resulted in a significant increase in oil rate productivity over the more conventional San Andres stimulation techniques. Additionally, the procedure has significantly reduced both the cost per barrel of oil increase, and the water rate increase typically observed foilowing stimulations at the Bennett Ranch Unit.

The hydraulic fracturing field test procedure is described and the interpretation summarized. Observations from the test are discussed and application of the data in stimulation designs is presented. Stimulation procedures evaluated in this study include; 1) fracture acidizing, 2) sand propped fracture treatments, 3) rock salt diverted acid treatments, and 4) acid soaks (or squeezes). A summary of the productivity results, by stimulation type, is presented and discussed.
Trends in World Crude Oil Production and Reserves
Authors: Babson E.C.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers, Inc.

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Trends in the growth of crude oil production and reserves in various areas of the world are presented graphically, illustrating the dramatic changes in distribution of crude oil availability during this period. While Eastern Hemisphere reserves passed those of the Western Hemisphere in 1945, production remained below that of the Western Hemisphere until 1962.

Reserve growth trends have been projected ten years into-the future in an effort to evaluate the future distribution of crude oil availability. It appears likely that U. S. reserves will decline, Western Hemisphere reserve growth will flatten, and Eastern Hemisphere reserve growth will continue approximately the present rate.

Introduction

The purpose of this discussion is to review past trends of crude oil production and reserves in various areas of the world in the hope that this study will throw some light on the future distribution of the world's oil resources. The importance of the subject is almost self evident because a modern industrial economy is almost completely dependent on an adequate supply of petroleum products and even the economies of the less developed nations would be severely crippled if the supply of these products were interrupted. Events of the last few months have reminded us dramatically that the location of petroleum reserves can be a matter of critical importance.

While some idea of present and future availability of crude oil from an area can be obtained by a study of production trends, reserves can be a more reliable guide although it is recognized that even reserve trends are not completely adequate for this purpose. The difficulty is in some degree the result of our concept of the meaning of the term "reserves". A proved petroleum reserve can be defined as a quantity of hydrocarbons, the presence of which can be proved to a high degree of probability and which can be recovered at a profit by presently known methods.
Application of Hydraulic Jet Pump Technology on an Offshore Production Facility
Authors: Boothby L. K. , Garred M. A. , Woods J. P.
Published: December 2007

A multiwell hydraulic jet pump lift system was installed on Tenneco Oil Company's Main Pass 297 "A" platform during the fall of 1986. The need for increasing reservoir voidage rates, beyond those observed using conventional gas-lift methods, was the main catalyst for this high volume lift system. The inefficiency of the gas lift system was attributed to the low gravity crude (19.4 degrees API), low reservoir pressure, and highly deviated wellbores (40–50 degrees).
Technical Considerations for Deepwater Pipeline Installation and Connections
Authors: Brown R. J.
Published: December 2007

During the past decade hydrocarbon energy related supplies have evolved from shortage to surplus. Naturally then, the cost of this energy has varied considerably with the market availability and demand. During the latter 1970's and early 1980's this market price supported exuberant installation costs, and the producers were still able to make attractive profits. As over production and competition increased the market experienced a drastic fall in price per barrel of oil produced. Also the number of extra large and giant oil fields have diminished which means the small or marginal fields are the largest number remaining for development. Marginal fields, because of their size, in the past, have been thought to be uneconomic by virtue of their costs of development based on the conventional methods of construction. In several recent developments the flowline and export lines have cost more than the drilling and production components. Hence, the Oil companies are now looking to new solutions to reduce costs to justify the development of new and marginal fields. With this new cost restraint has come re-appraisals of methods for developing fields and their transportation systems. A part of this re-appraisal of the pipelines is to look carefully at the installation methods from the stand point of cost of operations offshore specifically looking at the economics of the spread sizes and relate these to actual working and stand-by times.

The operating companies are looking more and more to engineering innovation to provide them with cost effective approaches for developing these transportation systems. The engineers problem now is to develop the methods and then convince the various non-technical management within the large operating companies that innovation can infact provide a low cost solution to their problems. This places a specific demand on the engineers abilities which, to date, have not been required to solve this type of specific situation and problem.

This paper describes the innovative technique of bottom towing coupled with diverless tie-ins for the Placid Green Canyon Block 29 Development. Also described is the latest techniques which have evolved making this towing technique cost effective and within acceptable risks during the pipelines installation, stabilization, and connection process.
NMR Imaging for Core Analysis
Authors: Edelstein W. A. , Vinegar H. J. , Tutunjian P. N. , Roemer P. B. , Mueller O. M.
Published: December 2007

2 Tesla, 12" horizontal bore NMR systems have been adapted for imaging/spectroscopy of oil cores. Strong and fast shielded gradients (up to 18 G/cm with a settling time of less than a few hundred microseconds) have been developed to produce good quality images of cores with very short relaxation times. Accurate and rapid spectroscopic porosity measurements have been made on carbonate and sandstone whole cores, including some shaly samples. Porosity images have been made of carbonates and clean sandstones. Oil/water saturation has been determined spectroscopically in carbonates and clean sandstones, and selective water and oil images have been produced. Other NMR nuclei, such as H2 (deuterium), C13, F19, and Na23 can be used for a variety of oil core applications. In particular, we have produced C13 spectra of oil in many different rocks; these spectra can potentially determine oil saturation in shaly materials where the proton NMR lines of oil and water overlap.1
Effect of Drainage Area Shapes on the Productivity of Horizontal Wells
Authors: Mutalik P. N. , Godbole S. P. , Joshi S. D.
Published: December 2007

This paper presents a technique to forecast the production from horizontal wells in rectangular drainage areas. The technique is useful for wells located either centrally or off-centrally in the areal drainage plane.

Analytical pressure transient solutions were used to calculate the shape factor, СA, and the corresponding equivalent skin factor, sCa. Moreover, dimensionless time at which the pseudo-steady state begins is reported for centered and off-centered horizontal wells and fully penetrating infinite-conductivity vertical fractures. These results are presented in the form of easy to use correlations. Furthermore, these correlations were tested by analyzing the relevant pressure transient data reported in the literature.

The pseudo-steady state shape factor, СA, and skin term, sCA, for a horizontal well approaches fully penetrating infinite-conductivity vertical fracture for very large values of dimensionless horizontal well length, LD. Knowledge of shape factor, СA, and of corresponding beginning of pseudo-steady state time, tDA, pss would facilitate computation of the horizontal well production forecast from a corresponding infinite-conductivity, fully penetrating vertical fracture forecast.

The methods for prediction of the inflow performance relationship for horizontal wells is also outlined, using example problems representative of horizontal well applications in on-shore and off-shore areas.
A Sensitivity Study on the Geological Factors Influencing the Oil Recovery from the Monterey Formation
Authors: Ucok H.
Published: December 2007

To gain insight into the influence of geologic factors on the oil recovery from the Monterey Formation, a 3D slice model was constructed to simulate the Monterey Reservoir using a single-porosity reservoir simulator.

The complex geology of the Monterey Formation, which resulted from nonuniform mineralogic diagenesis, was first simplified by grouping the different lithologies into two categories: Fractured lithologies and unfractured lithologies. This simplification reduced the highly fractured and interbedded Monterey geometry into a thinly layered system with drastically different physical properties which can be easily handled with conventional single-porosity reservoir simulators.

In the modeling, emphasis was given to the understanding of the effects of this highly laminated reservoir geometry, represented by layering of the model, on the primary oil recovery due to solution gas drive, gravity drainage and partial pressure maintenance. The diffusion and imbibition forces were not considered here.

The sensitivity of oil recovery from the Monterey Formation to the ratio of fracture to gross pay and to the permeability contrast between the different lithologies were also investigated.

The sensitivity study indicated that the fracture content of the Monterey formation has a strong influence on the producing life of the fields. The shale matrix contribution to oil recovery remained significant at matrix permeabilities equal or greater than one microdarcy. The gravity drainage substantially increased the oil recovery from the fractured layers. Similarly, partial pressure maintenance by injection of the produced gas also increased the oil recovery from the high conductivity layers. However, this improvement in recovery from fractured layers was more than balanced by the reduction in oil migration from the matrix. Thus, gas reinjection did not improve the overall oil recovery. Actually, partial pressure maintenance reduced the ultimate oil recovery from the Monterey Formation.
A New Method for the Measurement of Gas Relative Permeability and Water Saturation Simultaneously in Low-Permeability Cores
Authors: Narahara G. M. , Holditch S. A. , Moore K. R.
Published: December 2007

Since water is pumped into low permeability formations during stimulation treatments, two-phase rock property measurements are important if one wishes to model the effects of water upon gas recovery. Relative permeabilities are necessary to describe the flow of more than one phase in a porous medium.

Conventional steady-state measurements of relative permeabilities have extremely long stabilization times. Several days may be necessary to generate one relative permeability point. The determination of water saturations by gravimetrics may result in significant error due to handling of the core.

The purpose of this study is to present a new method for measuring gas relative permeability and water saturation simultaneously in low permeability cores. This two-phase transient technique incorporates the analytical solution developed in the early portion of this research project. Under conditions where the water is considered immobile and incompressible, the analytical solution can be used to match effective gas permeability and gas porosity simultaneously from the same transient data.

The new method has been verified with numerical simulation and actual measurements on cores. An extensive series of measurements were performed on two Travis Peak cores to measure the gas relative permeability curve, to check reproducibility of the measured values, and to establish the proper testing techniques.
A Flow Model Based on the Structure of Heterogeneous Porous Media
Authors: Narayanan K. , Deans H. A.
Published: December 2007

Laboratory and field experiments on carbonate core samples suggest that heterogeneities present on a centimeter scale control flow distribution. Heterogeneities on this scale are very important to local mass transfer process in this type of rock.

A three-parameter capacitance model called the ‘pore diffusion model’ has been used to simulate the nonideal features observed in carbonate tracer tests in both the laboratory and the field. The results from the lab tests indicate that even though the pore diffusion model can match experimental data very well, the model does not represent all the true mechanisms of mixing which take place in flow through vuggy cores such as those tested.

As a result an entirely different approach was pursued. Direct observations of flow structure were made using a fourth generation X-ray CT (Computed Tomography) scanner. Local concentration fluctuations on the centimeter heterogeneity scale are quite observable with a CT scanner.

Based on physical observations made using CT, a three-dimensional network cell model is proposed for this carbonate core sample. The model is a convection dominated dispersion model, and is based fundamentally on the heterogeneous nature of the rock. Dispersion behavior qualitatively similar to that predicted by the capacitance-dispersion model is shown to be produced by convection alone.

This work confirms that the nature of dispersion in highly heterogeneous porous media, at least on a laboratory scale, is convection-dominated rather than diffusion-dominated. Flow models based on convective mixing are more appropriate to characterize dispersion in laboratory scale systems compared to models that superimpose a diffusional process upon a convective flow field.