bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Waterflood Performance - Block VI Ranger Zone, Wilmington Field, Calif.
Authors: Roark Gene R.
Published: December 2007

An engineering analysis of the performance of the Block VI Ranger zone water flood operation from its inception in July, 1956, to date is presented. Implications of this performance with respect to future potential of a full-scale project are interpreted. Details are given of the expansion program currently underway, together with a description of the cooperative plan of operation in effect with offset operators.

The dual purpose to be accomplished in the flood is explained. The objectives are to effect an economic waterflood operation and to control subsidence of the overlying area through control of reservoir pressure. Reservoir engineering and mechanical problems connected with the operation are treated.

Introduction

The first waterflooding Operations in the Ranger zone of Wilmington field, Los Angeles County, Calif., were initiated in July, 1956, as a pilot operation on the Producing Properties, Inc., N–1 and S–1 leases in Fault Block VI. The project is situated near the most easterly extension of the field and in the region where the Ranger zone underlies the downtown area of the city of Long Beach.

The N–1 and S–1 leases of Producing Properties, Inc. are communitized leases comprising approximately 346 acres of town-lot development. Because the drilling of oil wells is prohibited by city ordinance within the area of these leases, the development drilling was accomplished from drill sites located on the west berm of the Los Angeles County flood control channel. This strip, which is located approximately 1,400-ft west of the western limit of Fault Block VI, is 26-ft wide and 5,570-ft long.

As will be seen later, the fact that all wells producing from the properties are slant holes drilled from the western drill site has created unique problems in waterflood planning and in interpretation of the results observed in the pilot operations to date.

At the time pilot operations were commenced, a total of 65 producing wells existed on the two leases in Fault Block VI; cumulative production had reached 8,889,773 bbl of oil, 12,191,422 Mcf of gas and 398,214 bbl of water. The Parcel A properties of the city of Long Beach. operated by Richfield Oil Corp. and bordering the pilot area to the south, had reached a development of 20 wells and had produced 2,348,465 bbl of oil, 3,764,623 Mcf of gas and 79,607 bbl of water. Development drilling in Fault Block VI of the Ranger zone stops at Pine Avenue in the city of Long Beach, or at its linear projection. The oil-productive Ranger zone unquestionably extends to the east in substantial development beyond this arbitrary boundary. The pilot area is offset to the north by the E. C. Simmons N–3 lease which had two producing wells and had produced 141,315 bbl of oil, 218,046 Mcf of gas and 11,531 bbl of water. Thus, at the commencement of the pilot operation. cumulative production from the Fault Block VI Ranger zone had been 11,379,553 bbl of oil, 16,174,091 Mcf of gas and 489,352 bbl of water.
Slug Size and Mobility Requirements for Chemically Enhanced Oil Recovery Within Heterogeneous Reservoirs
Authors: Wright R. J. , Wheat M. R. , Dawe R. A.
Published: December 2007

The influence of fluid mobilities on channeling and crossflow is demonstrated and quantified in systems containing thin high-permeability layers. Flow visualization of continuous and slug-mode displacements was performed under conditions in which capillary pressure, gravity, and dispersion were insignificant. The data from numerous experiments were correlated by a mathematical model and the viscous crossflow effects for layered media quantified. The analytical approximation, although simple, is novel and gives good agreement with the data. Such a model is essential for the initial design of stable slugs before computer simulation of the oil recovery process. For heterogeneous reservoirs, prevention of slug disintegration caused by chase fluid bypassing clearly requires oil recovery agent plus mobility buffer quantities of around 1 PV and stringent mobility balancing. The slug design criteria are more demanding than previously thought necessary for reservoirs with normal degrees of heterogeneity.

The initial assessment of chemical EOR schemes, especially polymer flooding and surfactant/polymer methods, should be aided by our design criteria, which also provides guidelines for optimization of the slug size and its chemical concentration.
Application of Exploration and Production Cost Trends to Determination of Fair-Market Gas Prices
Authors: Eggleston W.S.
Published: December 2007

The purpose of this paper is to outline a method of determining fair-market prices for gas sold in interstate commerce.

The Supreme Court of the United States, in the Phillips Decision of 1954, held that a producer who sells gas in interstate commerce is subject to regulation by the Federal Power Commission. The Federal Power Commission was, in effect, ordered to regulate gas prices paid to gas producers.

It has been interpreted by the courts that under utility-type regulation it is necessary to consider the cost of service of producing gas in determining a just and reasonable price. Neither the Federal Power Commission nor the gas producers have been able to establish fair and reasonable prices in any instance based on this concept. One important reason for such failure can be attributed to the impossible task of allocating costs between oil and gas on a realistic basis.

A more practical approach to this problem would be to use as a starting point prices established in a competitive market prior to regulation, adjusted for increases in costs since that time. The average weighted increase in the costs of exploration and production over the past 10 years amounts to approximately 108 percent. The application of this weighted increase in costs to prices established in 1948 can be used to determine prices for current years as a point of departure for the purpose of establishing specific prices.

Points of departure determined by this method indicate a price of 17.7 cents/Mcf in 1957, 19 cents/Mcf in 1958 and approximately 21 cents/Mfc in 1959 for South Louisiana. Specific prices for this area could be determined by such modifying factors as reserves, deliverability, location, quality and pressure of the gas.

Introduction

Technical journals and magazines periodically have carried articles on the increasing costs of both exploration and production. As a rule, these studies are expressed in terms of cost per barrel of oil found and of oil produced. This is only natural because, after all, we have all grown up under an oil economy where a barrel of oil was the basic measuring unit. Traditionally, where gas and oil were produced together, most of the income and all of the costs have been related to a barrel of oil - gas was only a by-product or a fire hazard; it was flared or sold at give-away prices.
Severe Slug Flow in Offshore Flowline/Riser Systems
Authors: Pots Bert F. M. , Bromilow Ian G. , Konijn Martin J. W. F.
Published: December 2007

Small-scale experiments are described that simulate the unstable two-phase flow pattern of severe slugging often found in offshore flowline/riser systems. In particular, the effects of riser-base supplementary gas lift, flowline orientation, and liquid viscosity have been examined. To place the tests in perspective, the physics of severe slugging is discussed, including a method for scaling between model and prototype situations. Test results are compared with a simple hydrodynamic computer model.
Process Simulators for Oil- and Gas-Plant Operators
Authors: Dempsey J. , Richardson J. L.
Published: December 2007

Process simulators have been used for some years in the oil and gas industries. As a training device, the simulators allow the trainee to perform plant or platform operations under normal and abnormal conditions without risk to personnel, equipment, or production. Startup and commissioning phases of new plants and processes are shortened and proceed more smoothly because tasks have been rehearsed through simulation. This paper describes how simulator systems have been successfully integrated into an operator training program.
Design and Installation of a High-Pressure Gas Cycling System
Authors: Stallings Lynn W.
Published: December 2007

The Gillis-English Bayou field is ahigh pressure gas reservoir locatedapproximately five miles north ofLake Charles, La., in CalcasieuParish. The field was discovered by SunOil Co. with the drilling of the LayneLouisiana Co. Well No. 1 in Dec.,1961. Sun Oil and others have drilleda number of wells in this reservoirin the last four years. Since thereservoir was found to be a gas phaseaccumulation, which had severeretrograde condensation characteristics, a gas cycling program was begun toobtain maximum liquid recovery. Agas cycling unit called the UpperHackberry Unit was established byorder of the Louisiana Department ofConservation in Nov., 1964. The need to inject gas in the wellswhich had tubing pressures of 5,000psi presented mechanical designproblems previously not encountered bySun Oil in the Gulf Coast Division. Extensive investigation revealed threeor four places in the southern UnitedStates where injection compressorswere being operated at the highpressures expected in this project. Production control of the wells, processing of the gas and oil for injectionand sale, respectively, and safe, unattended operation of the entirefacility and associated properties wereall factors considered duringplanning of this program. This paperdescribes design considerations and theparticular items of equipment used toaccomplish the gas cycling programwhich has been in operation forapproximately one year.

Introduction

The Upper Hackberry reservoir ofthe Gillis-English Bayou field hasfour sands occurring in threelocalities, or a total Of nine sandaccumulations, all in pressure communicationand Comprising a single reservoir. These sands occur between twounconformities and are productive atdepths ranging from approximately9,750 to 10,020 ft (Fig. 1). Bottom-hole pressure data andanalyses of recombined reservoir fluidsamples indicate the reservoir fluid tobe in a vapor phase with a 7,000-psidew point. Further, there is noindication of a significant water drive inthe reservoir. Reservoir fluid analyseshave indicated severe retrogradecondensation. This, in conjunction withthe depletion-type drive mechanism, will result in 84 per cent loss ofinplace reservoir liquids which wouldrepresent a 13 million bbl loss ofliquids if preventive measures were nottaken. To prevent these losses, SunOil decided to instigate a gas cyclingprogram. Parties with an interest inthe reservoir were contacted during1963 and advised of Sun's programand plans to establish a LouisianaDepartment of Conservation unit forthe purpose of gas cycling. A formalhearing was held in Sept., 1964, andthe resultant order was issuedeffective Nov. 1, 1964; gas cycling wasinitiated Jan. 24, 1965.

JPT

P. 1286ˆ
Effect of Completion Fluids on Well Productivity in Permafrost, Umiat Field, Alaska
Authors: Gates George L. , Caraway W. Hodge
Published: December 2007

Introduction

During the years from 1944 to 1953, the U. S. Navy conducted an extensive exploration program in U. S. Naval Petroleum Reserve No.4, northern Alaska, to determine the oil possibilities. The area was designated a petroleum reserve by the U. S. Congress in 1923 and consists of approximately 37,000 square miles.

As a cooperating agency, the Geological Survey, U. S. Department of the Interior, made an extensive study of the area both in the field and in the laboratory, and reports have been published describing the general characteristics and geology of the region.

The exploratory program included several test wells on the Umiat structure in the southeastern part of the naval reserve. Of the 11 wells drilled, some were productive and some were not, but oil-bearing cores or other indications of oil were obtained from all. Several types of drilling muds were used including fresh-water muds, salt-water muds, emulsion muds and oil-base muds. At the request of the navy, the Bureau of Mines of the U. S. Department of the Interior, cooperated in the program to obtain and study the cores and core data and to determine the best completion practice.

Recently, information on these wells was removed from the restricted classification, and a study of the relation of completion methods and well productivity has been conducted so that the experience in this field may be made available.

Physiography

The Umiat field is located in the southeastern part of Naval Petroleum Reserve No.4 on the Arctic slope and lies entirely within the continuous-permafrost zone (as shown in Fig. 1). The Arctic slope is bounded on the south by the crest of the Brooks Range and on the north by the Arctic ocean. The Brooks Range, the Alaskan counterpart of the Rocky Mountains, encompasses several groups of rugged, glaciated mountains having a relief of 3,000 to 6,000 ft and maximum altitudes of 3,600 to 9,200 ft. Anaktuvuk Pass, at an altitude of 2,200 ft, is the highest elevation on the land route between Fairbanks and the Arctic plain.
Proppant-Settling Correlations for Non-Newtonian Fluids
Authors: Shah Subhash N.
Published: December 2007

This paper expands and improves the data analysis for estimating particle-settling velocity in non-Newtonian fracturing fluids. It is shown that the available settling-velocity correlations for Newtonian fluids cannot be used for non-Newtonian fluids when an apparent viscosity term is substituted for Newtonian viscosity. Significant deviation from Newtonian correlations has been shown if such an approach is taken.
A Digital Filter for Data Smoothing With Application to Relative Permeability Estimation
Authors: Tao T. M. , Kerig P. D. , Watson A. T.
Published: December 2007

Automatic data acquisition systems that allow data to be sampled very rapidly can provide much more information from experiments than manual data sampling. Computer storage and work requirements for interpretive procedures for calculating rock properties from measured data, however, generally increase significantly with the number of data. Rather than choosing a sampling rate on the basis of work requirements of· the interpretive procedure, we recommend sampling as frequently as possible. Improved estimates for data values to be used in the interpretive procedure can then be obtained by a smoothing process.

We present a simple digital filter for data smoothing. We evaluate improvements in relative permeability estimates that may be obtained when the digital filter is used with data collected from displacement experiments. The use of the digital filter can result in significant improvement in the accuracy of relative permeability estimates.
Short-Term Transient-Rate and Pressure-Buildup Analysis of Low-Permeability Reservoirs
Authors: Ahmed Usman , Kuchuk Fikri , Ayestaran Luis
Published: December 2007

A majority of low-permeability wells, both unfractured and fractured, are analyzed with the conventional transient-pressure-buildup test. Application of this technique to wells faced with wellbore storage, even small amounts, can be time-consuming and may not provide accurate answers. Wellbore storage and its effect on the transient regime duration distorts early-time data. Such early-time data could range from a couple of hours to days and weeks. This constraint makes long-term data necessary and does not allow the interpretation of early transients reflective of near-wellbore conditions that are unaffected by outer boundary effects.

This paper presents a technique that reduces test time considerably and obtains accurate formation flow properties before any boundary effects are felt. The technique involves measuring transient rate and pressure at the wellbore during the buildup period and a few minutes before the surface shut-in of the well. The technique is called TRAP™ (transient rate and pressure) analysis. Having the transient rate during the pressure buildup allows the engineer to correct the pressure data collected during the early portion and to perform the analysis for permeability, skin factor, reservoir pressure, and other formation characteristics.

A field example is presented to show the effectiveness of the technique in analyzing low-permeability reservoirs.
Peripheral Water Flood as a Supplement to Gas Injection Pressure Maintenance
Authors: Storer T.C. , Plaza J.B.
Published: December 2007

Wiliamar West field has been operated with a crestal gas injection program for several years. The analysis and its results which led to the decision to water flood the field are discussed. Economics based on this analysis appear to be favorable for the simultaneous application of both gas and water injection.

Introduction

Willamar West is a field in which a successful gas injection pressure maintenance program, started during the primary life of the reservoir, is to have a peripheral water flood imposed also, the two to operate simultaneously at opposite sides of the oil column. The Willamar West unit's working interest owners have only recently agreed to water flood the Willamar pay zone; consequently, only the theoretical considerations leading to that decision can be shown at this time.

History of Unit

Willamar West field is located in east Willacy County approximately 12 miles east of Raymondville, Tex. The Willamar structure is separated by faults into three main producing areas. These areas (Fig. 1) have been designated Willamar West field, Willamar North Graben field and Willamar field by the Railroad Commission of Texas. The Willamar field was discovered by Pan American Production Co.'s Willamar Community Well No. 1 in March, 1941. Subsequent drilling resulted in the discovery of Willamar West reservoir by the completion of Pan American Production Co.'s Kent No. 1. The field was developed very slowly during World War II. However, development was more rapid after 1944, and the field was completely developed for all practical purposes by 1947.

The allowable was initially 103 B/D/well, and all of the three Willamar producing areas were considered as having one field MER. As a result of plummeting bottomhole pressures and a rising field GOR, this MER was reduced in 1949 to permit more efficient use of the expansive energy of gas caps and aquifer (particularly the caps). Because of a growing concern over pressure decline and the flaring of casinghead gas, the Willamar Engineering Committee was formed which, with the help of consultant's studies, investigated the advantages of gas injection.
Performance of Seeligson Zone 20-B Enriched Gas-Drive Project
Authors: Baugh E.G.
Published: December 2007

An enriched gas-drive project was initiated in Zone 20-B, Seeligson field, Jim Wells and Kleberg counties, Tex., on March 19, 1957. To date nearly 2.5 billion cu ft of an enriched gas mixture composed of about 50 per cent methane and 50 per cent propane has been injected through two injection wells. There are 11 producing wells in this project. Cumulative production since injection began is approximately 750,000 bbl of stock-tank oil, and the current oil-producing rate for the reservoir is 1,000 bbl per calendar day.

Enriched gas in appreciable quantities has reached the first row of producing wells down-structure of the two injection wells. As predicted from laboratory work, displacement of reservoir oil by the enriched gas mixture has proved to be highly efficient. Project results to date are encouraging, and additional information should be gained from a conformance evaluation workover to be performed in the near future. The project is still at an early stage of operation because the enriched gas volume injected to date is only 16 per cent of the hydrocarbon pore volume.

Introduction

The enriched gas-drive process entails the injection of a gas which has been enriched through the addition of such intermediate hydrocarbon components as ethane and propane to the extent that it is completely soluble in the oil to be displaced. Enriching components in the gas are absorbed into the oil, forming a bank of swelled oil that is miscible with the oil ahead and the gas behind. There is no sharp interface between the displaced and displacing fluids; rather, there is a zone of short duration between the injected and resident fluids in which the fluid properties grade from those of the displaced to the displacing medium. Under these conditions, capillary and interfacial tension forces are not believed to be present. High recovery is made possible by removing or reducing the interfacial tension between the injected material and the reservoir oil to the extent that essentially no oil is left as residual droplets.
Miscible Slug Flooding - A Review
Authors: Craig F.F. , Owens W.W.
Published: December 2007

Over the past several years the petroleum industry has become increasingly interested in the possibilities of miscible slug flooding as a means of increasing the nation's recoverable reserves. Preliminary studies of this recovery method have demonstrated that substantially complete displacement of oil is obtained in those portions of the reservoir contacted by the miscible slug.

A large portion of the published research has been concerned with the volume of solvent slug required to maintain miscibility between the reservoir oil and the scavenging gas. In this paper laboratory results are reviewed with particular emphasis on the general conclusions of the studies as applied to field application of miscible flooding.

The factors affecting the portion of the reservoir swept by the miscible slug and reservoir conditions believed desirable for successful operation are discussed. Possible methods for improving the sweep efficiency are considered.

Introduction

During its growth, the petroleum production industry has continually sought improved methods for recovery of oil from underground reservoirs. Gas and water injection have been used to flush additional oil from formations and to restore and maintain reservoir pressure. However, even with these injection operations generally from one-third to one-half of the oil originally in place remains unrecovered at the time that further production becomes uneconomical. This lack of complete oil recovery is due to the inability to obtain both complete sweep of all oil-bearing portions of the reservoir (100 per cent volumetric sweep efficiency) and complete displacement of oil from the swept regions (100 per cent displacement efficiency).

The volumetric sweep efficiency during any injection operation depends uponthe nature and distribution of reservoir nonuniformities,well pattern effects, andgravity effects caused by the density difference between the oil and the injected fluid.
Five-Spot vs. Crestal Waterflood Patterns, Comparison of Results in Thin Reservoirs
Authors: Leissner E.L.
Published: December 2007

This paper presents a comparison of results for two different waterflood patterns which were utilized in separate reservoirs of the same producing horizon. The El Javali field is located in South Texas, about 30 miles north of Rio Grande City on the Jim Hogg County-Starr County boundary. The field is composed of two separate reservoirs separated by a shale-out. The production from the El Javali field is obtained from the O'Hern sand of Eocene age at approximately 2,300 ft. The field was discovered in Oct., 1951. Porosities are good, permeabilities are low, connate-water content in average and the sand thickness is thin. The oil gravity is 32°API and the viscosity is relatively low. Studies of secondary possibilities were initiated in early 1955 to conduct waterflood operations in the north reservoir. Water injection was commenced in this reservoir in May, 1956, by utilizing a crestal, or line, flood pattern in two injection wells and five producers. Primary recovery in this reservoir amounted to 297 bbl of oil/acre-ft. Secondary recovery, as of July, 1959, for the north reservoir was 102 bbl of oil/acre-ft. It is anticipated that the total secondary recovery from this reservoir will be about 157 bbl of oil/acre-ft. In Sept., 1957, water injection was begun in the south reservoir by injection into 10 injection wells forming three modified 20-acre five-spots. Primary production from this reservoir was 316 bbl of oil/acre-ft. Water flood recovery in the reservoir, as of July, 1959, was 81 bbl of oil/acre-ft; the ultimate secondary recovery is estimated to be at least 200 bbl/acre-ft. Secondary increases in production in the north reservoir were experienced in one well at a time. The secondary "kicks" in production for the south reservoir have been more or less simultaneous for all of the producers. From the data presented, it can be seen that the five-spot project will ultimately recover some 21 per cent more secondary oil per acre-foot than the crestal pattern flood.
A Pressure-History-Matching Method for Determination of Relative Permeabilities
Authors: Lai W. , Brandt H.
Published: December 2007

A pressure-history-matching method for determining relative permeabilities was developed and verified in a one-dimensional (1D), analytical/experimental study. The matching method is based on a pressure history induced by injecting a gas (nitrogen in this study) into an incompressible-fluid-saturated porous medium.

The analytical model uses relative permeabilities expressed as two-parameter functions of saturation. A parametric study with a finite-difference implicit pressure, explicit saturation (IMPES) solution of the analytical model showed that the relative permeabilities can be determined by matching pressure histories in three steps: (1) match calculated pressure history with measured pressure history during the initial period of 1% of the total injection time, (2) match calculated pressure history with measured pressure history during the final period of 1 % of the total injection time, and (3) minimize differences between calculated and measured pressure histories at no fewer than three selected intermediate times. The parametric study also showed that determining relative permeabilities with this pressure-history-matching method requires a knowledge of porosity and specific permeability.

Experimental verification compared relative permeabilities of a core determined by the pressure-history-matching method with the relative permeabilities measured by the classic transient-displacement method. The comparison showed errors in the relative permeability of ±5% for water flow and +30% for gas flow.
The Rheological Properties of Cement Slurries: Effects of Vibration, Hydration Conditions, and Additives
Authors: Chow Thomas W. , Mcintire L. V. , Kunze Kenneth R. , Cooke Claude E.
Published: December 2007

Dynamic material testing was used to study cement-slurry structure during early setting. The structure is very sensitive to shear strain and, to a lesser degree, to vibrational frequency. Both setting kinetics and cement structure can be affected by hydration conditions, including water content, temperature, and commonly used additives.
Performance of an Alternate Repressuring and Producing Project
Authors: Crosby George E. , Cochran Robert J.
Published: December 2007

Introduction

A reservoir which is being subjected to an alternate repressuring and producing mechanism is the Rincon field Frio D–7 sand lens located 16 miles northeast of Rio Grande City, Starr County, Tex., along the Vicksburg flexure and the southwestern edge of the Rio Grande embayment. As in most Frio fields in this area, numerous sand lenses are encountered and, in this instance, throughout 12 distinct strata. The subject reservoir, the D–7, was the seventh reservoir to be outlined in the D stratum. The D–7 reservoir shown in Fig. 1 is a 38 acre-ft, sand lens located at a subsea depth of - 3,230 ft on the west side of the Rincon structure. Only two wells, T. B. Slick HB No. 90 and 91, were drilled into the sand lens, encountering 12 and 16 ft of sand, respectively. Although Well No. 91 was cored, no analysis was obtained; therefore, 23 per cent porosity and an irreducible water saturation of 24 per cent, the average figures in Frio D sands in this area, were used. A fluid analysis is not available from the D–7 reservoir. Therefore, an analysis from the D–5 reservoir (sand) in proximity to the subject reservoir was used to obtain the assumed formation volume factor of 1.172 at 1,523 psi and 155°F.

Primary Performance History

In June, 1941, the T. B. Slick HB No. 91, the only well that produced during primary operations, was completed in the D–7 reservoir and potentialed for 166 B/D, no water, flowing through a 1 1/64 in. choke with a GOR of 311 cu ft/bbl, and tubing pressure of 320 psi. Flow valves were installed in Aug., 1944; in Feb., 1946, the well was shut in due to low productivity. The flow valves were repaired in Dec., 1947, and the well was re-potentialed for 45 B/D. The well then produced until Feb. 21, 1950, at which time it was permanently shut in due to low productivity. The primary production history of the reservoir is illustrated in Fig. 2. Cumulative production at the end of the primary life was 80,820 bbl of oil, no water and 159,872 Mcf of gas. Bottom-hole pressures taken in 1948, 1950 and 1951 are thought to be in error and probably represent gas-lift system pressures caused by a leaking valve. The gas-oil ratio increased from 311 to 52,800 cu ft/bbl, but the accuracy of the erratic gas-oil ratio history after 1946 is questionable and can probably be contributed to the inherent industry-wide problem of measuring injection gas during intermittent gas-lift operations.
Feasibility of Underground Storage of Liquefied Methane
Authors: Flanagan D.A. , Crawford Paul B.
Published: December 2007

A study has been made of the feasibility of storing liquid methane at low pressures in underground caverns. Methane liquefies at - 258F at atmospheric pressure. It is shown that the methane evaporation rates will rapidly decrease and cool the surrounding rock so that at the end of one month they would be between 50 Mcf/hr for a cavern of 25-ft radius and 700 Mcf/hr for a cavern of 100-ft radius. At the end of 10 years, the evaporation rates would be 18 and 100 Mcf/hr, respectively, for caverns of the same radii. The evaporation rates may be reduced by a factor of 2 to 10 by the application of insulation.

The cost for mining the caverns is estimated to be $.75 to $1.25/Mcf of storage. This is substantially less than surface storage; it is believed to be safer and to result in lower maintenance, savings in space and savings in strategic materials.

Introduction

During the past few years, there has been an increasing interest in the economic feasibility of liquefying methane. Methane liquefaction is being considered for tanker transport; in addition, liquefaction is being reconsidered for shaving peak gas demands. Several articles have described natural gas liquefaction and the progress of the tanker in making trial runs from the United States to Great Britain to determine the feasibility of tanker transport.

At the present time, pipelines are not designed to supply peak gas loads during extremely cold periods such as are often encountered in the North and Northeast. Gas is being stored in underground reservoirs enroute to its destination, but in many instances satisfactory storage in porous reservoirs has not been practical, especially along the Eastern seaboard where few petroleum reservoirs have been found. In England and other foreign countries, it is unlikely that satisfactory porous structures could be found, and it may be desirable to mine or excavate the rock to obtain storage. By storing the methane near the consumption point, product availability can be increased during periods of need.
Overview of the Highlander Field Development
Authors: Smith G. D. , Batcheler G. H.
Published: December 2007

This paper discusses the engineering, operational, and construction challenges encountered in the Highlander development and how the various elements of the Highlander production facilities were designed to provide economical solutions. Outlined descriptions of facilities are given to show the comprehensive nature of the project. The application of innovative designs, fast-track scheduling, tight budgetary controls, and stringent quality control are discussed.
A Subsea Completion System for Deep Water
Authors: Rigg A.M. , Childers T.W. , Corley C.B.
Published: December 2007

As the search for oil and gas reserves is extended to deeper water, conventional offshore exploitation methods become less attractive due to the high cost for fixed platforms. This has prompted consideration of subsea completion methods as an alternative development technique. Humble Oil and Refining Co. has conducted tests to develop technology and equipment needed for completion and production maintenance of satellite underwater wells in deep water. Results of this development program are presented.

Introduction

The development of offshore oil and gas fields has largely been conducted from permanent pile-supported platforms using directional drilling techniques. Wells are drilled through large diameter conductors and wellhead equipment is installed on the platform deck. Permanent-type platforms have been installed in water depths to 285 ft. As activity moves into deeper water, the investment required for fixed platforms increases rapidly. This has prompted consideration of alternate development techniques for deep water using floating drilling and subsea completion methods. Floating rigs have been widely used as a deep water exploratory tool and techniques and equipment are now in an advanced state of development. For example, Humble recently drilled an exploratory well from a floating vessel in 632 ft of water offshore California. Industry experience is rather limited, however, with the completion and production of underwater wells. Most have used adaptations of conventional land equipment and have been completed in water depths easily accessible to divers. The extension of offshore operations to the edges of the continental shelves, and even beyond, has accelerated interest in the use of subsea completion techniques. To provide the technology and equipment needed for the completion and production maintenance of satellite underwater wells in deep water, Humble has prompted development of

an underwater well completion system, an underwater Christmas tree system, and the tools and techniques required for performing well servicing and simple workover operations from a remote location.

All equipment has been designed for remote diverless installation and operation. As a part of this program, an off. shore underwater test well has been completed and production experience has been accumulated over an extended period.

Underwater Well Completion System

The well completion system for satellite underwater wells (Fig. 1) was designed so that routine production maintenance and simple workover operations could be performed from a remote location with access to the well tubing through the flowline.

JPT

P. 1049ˆ
An Analysis of Upstream Differencing
Authors: Sammon Peter H.
Published: December 2007

A complete convergence analysis is carried out for upstream differencing as applied to one-dimensional (ID) tilted reservoirs experiencing gravity-segregation effects and possible countercurrent flows. It is shown that the standard upstream method converges to the correct physical solution of this problem, provided that an appropriate stability condition holds. Results from the theory of monotone-difference schemes are used. It is concluded that in addition to the practical advantages of the upstream formulation, there is also a strong theoretical justification for use of upstream techniques in multidimensional reservoir simulation.
Well-Test Analysis for Multiphase Flow
Authors: Raghavan Rajagopal
Published: December 2007

This paper is a review of well-test analysis under multiphase-flow conditions. The contributions of Perrine and Martin are noted, and the consequences of using their results are documented. The advantages of incorporating the heterogeneous nature of the porous medium for solution-gas-drive systems with the pseudopressure function are discussed. Methods to predict well-inflow performance are discussed with regard to the works of Vogel and Fetkovich. The long-time-performance prediction of wells with decline curves that incorporate the heterogeneous nature of the porous medium is addressed. The final part of this paper considers pressure-falloff data. Theoretical developments are reviewed, and problems associated with the identification of fluid banks are listed.
Reservoir Performance Under Gas Injection, LL-453 Area, Bolivar Coastal Field, Venezuela
Authors: Stepanek D.L.
Published: December 2007

The Tia Juana conservation plant No. 2, which furnishes high pressure gas to pressure maintain four Eocene sandstone reservoirs of the prolific LL–453 area of the Bolivar Coastal field, was placed in operation during April, 1597. This is Creole Petroleum Corp.'s largest gas conservation plant to be constructed on Lake Maracaibo to date, and is capable of compressing 300 MMcf/D to 1,800 psig. The four reservoirs being pressure maintained extend over a surface area of 10,400 acres, with each having an average net oil-sand thickness of 114 ft. During the first 28 months of plant operation, an average total of 205 MMcf/D of gas was injected into the four reservoirs. This represents approximately 99 per cent replacement of hydrocarbon volume withdrawals. The total efficient producing rate of these reservoirs is 135,000 BOPD with a gas-oil ratio of 1,050 scf/bbl. The highly effective gravity segregation taking place throughout the reservoirs contributes quite heavily to the excellent reservoir performance experienced to date, under both natural depletion and pressure maintenance. Although gas injection has only been in operation for approximately 28 months, the beneficial effects are readily apparent from the production characteristics of up-dip wells. These wells have shown decreasing trends in gas-oil ratios accompanied by an increase in production rates. Furthermore, recent subsurface pressure surveys have indicated definite pressure increases in the up-dip portion as a result of the gas injection.

Reservoir Characteristics and Development History

The LL–453 area is located on Lake Maracaibo, approximately 11 miles southwest of the community of Tia Juana, Venezuela. The pressure maintenance area covers a surface area of 10,400 acres and consists of two B–6-X and two underlying B–7-X Eocene sandstone reservoirs, each of which has a net oil-sand thickness (when averaged together) of 114 ft. Structurally, the reservoirs are gently dipping monoclines bounded down-dip by essentially immobile water legs, up-dip by eroded or truncated zones resulting from the Major Miocene-Eocene Unconformity and laterally by major faulting. Shown in Fig. 1 is a structural map of the LL–453 pressure maintenance area. The total sand-section thickness of the B–6-X and B–7-X sands (when considered together) varies between 0 to 400 ft, depending on the structural position.
Slug-Catcher Design for Dynamic Slugging in an Offshore Production Facility
Authors: Miyoshi M. , Doty D. R. , Schmidt Z.
Published: December 2007

A hydrodynamic model is developed for a typical offshore gathering system that consists of a pipeline, riser pipe, and slug-catching separator. The dynamic model is capable of determining the dynamic interaction between the slug-catching separator and the pipeline slug flow. In particular, a procedure is incorporated into the model for directly predicting the separator foam layer associated with the crude-oil stream. The model is capable of predicting all variables necessary for slug-catcher design.

The influence of several variables—including the riser-pipe height, separator foam volume, and incoming slug size—on separator performance is examined. The analysis shows that each is critical to proper sizing of a slug-catching separator.
Pin-Point Sandfracturing - A Method of Simultaneous Injection into Selected Sands
Authors: Murphy W.B. , Juch A.H.
Published: December 2007

The conventional sandfracturing techniques first adopted by the Lagunillas Land Dist. of Cia. Shell de Venezuela in its Eocene wells, which had been perforated with four holes/ft over the full NOS interval, resulted in production increases which averaged some 700 per cent.

However, recent developments in completion technique not only have reduced completion costs, but also have resulted in a further appreciable increase in production. Production rates of the new completions over the first year after sand fracturing are some 60 to 90 per cent higher than those of the "conventional" completions.

It is believed that, by having a limited number of perforations and always providing an injection capacity which theoretically is greater than the total capacity of the perforations, there is a greater likelihood of fracturing all sands simultaneously.

It is estimated that the technique reduces completion costs by $3,700.

Introduction

Productive prospects have been known to exist in the Eocene formations on the eastern shore of Lake Maracaibo for some time, but it was not until the successful introduction of sandfracturing as a stimulation technique that these could be economically exploited. Cia. Shell de Venezuela's Eocene land activity has, in the main, been concentrated in the Lagunillas, Tia Juana and (to a lesser extent) Cabimas fields; (these three fields comprise the company's Lagunillas Land Dist. By Feb., 1959, a total of 155 Eocene wells had been completed as economic producers after receiving a sandfracturing stimulation treatment.

The productive shallow Eocene (B.1 sand), encountered between 1,000 and 3,000 ft, has gross intervals from 50 to 1,000 ft and is composed of interbedded shales and fine- to medium-grained consolidated sandstones. The sandstones make up, on the average, some 50 per cent of the section, but permeability (as shown by the Microlog) is restricted to some 60 per cent of the total sandstone development. The shallow Eocene is productive in the Lagunillas, Main Tia Juana and Cabimas fields.
Analysis of Geothermal Wells in Naturally Fractured Formations With Rate-Sensitive Flow
Authors: Morris C. W. , Campbell D. A. , Petty S.
Published: December 2007

Production data are presented that show the nonlinear flow behavior for high-rate geothermal wells in liquid-dominated, naturally fractured formations, and comparisons are made between various theories for describing this rate-sensitive phenomenon. The test data indicate that the pressure drawdown relationship with flow rate has a component proportional to flow rate, squared. Two fracture-closure theories gave inadequate results for predicting well performance.
The World Oil Industry and Its Challenge to the Technical Man in Venezuela
Authors: Vazquez Siro
Published: December 2007

Most of the nearly 30 years of my professional life I have worked as a technical man in the Venezuelan petroleum industry. I saw this industry grow from its infancy in the early 1930's into the mature and great enterprise which it is today. I saw our technology develop from its incipient and rather empirical beginnings into the complex of sciences now in general and successful use for the finding, producing, refining and distribution of our oil. To have lived with these developments through the years, to have been an integral part of the group of people that brought them about, and to have participated from day to day and year to year in the development and utilization of better techniques in an effort to keep our industry efficient and competitive has been indeed a great privilege. It has also been a most rewarding personal experience, for through all these years, these endeavors brought me into close association with an outstanding group of people-many of them my Venezuelan compatriots, many of them citizens of friendly nations who adopted Venezuela as their working home and who in the industry and in the government have worked shoulder to shoulder to bring about the progress of the Venezuelan petroleum industry, and thereby the progress of Venezuela and of its great oil enterprises. It is hard to conceive of a more outstanding group of people anywhere in the world-outstanding in ability, honesty, loyalty and friendliness. Many of my old friends are here today; to you, as well as to the younger members of our technical community, go my most cordial greetings. I wish now to bring to you an appealan appeal to use your ability and devotion to make our industry more efficient and more competitive. To understand the nature of this challenge, it is necessary to understand the profound change that has taken place in the nature of the petroleum industry during the last decade change that has converted it from a producer's paradise in a seller's market into an industry characterized by a most competitive buyer's market under a serious oversupply condition.
A New High-Speed Hybrid Technique for Simulation and Inversion of Resistivity Logs
Authors: Glanzero Stan , Lin Ylh-ylh , Su Shey-Min
Published: December 2007

The inversion of resistivity logs with multiple bed boundaries is of vital interest to log analysts, but previously published methods have been optimized for cases of many radial boundaries with a serious loss of speed when many bed boundaries are considered. This paper describes a hybrid solution (analytic radially and numeric vertically) that can simulate a 100-ft [30.4-m] log with 25 beds in less than 12 minutes on an IBM 3081.

The model assumes axial symmetry with no dip and with the tool centered in the borehole. Decomposition of the measured potential into the product of two independent functions describing its radial and axial dependence allows us to choose the best method for evaluating each function. For the case dominated by bed boundaries, the most efficient choice is to obtain the radial solution analytically by means of a finite number of modes and to obtain the axial solution using piecewise continuous functions.

Several simulations are presented of the dual laterolog (DLL) in multibed cases with invasion, and the results are combined in a least-squares inversion technique to demonstrate the derivation of true resistivity profiles from real logs.
Pressure Analysis for Horizontal Wells
Authors: Daviau F. , Mouronval G. , Bourdarot G. , Curutchet P.
Published: December 2007

This paper presents horizontal-well test design and interpretation methods. Analytical solutions are developed that can be handled easily by a desktop computer to carry out design as well as interpretation with semilog and log-log analysis. These analytical solutions point out the distinctive behavior of horizontal wells: (1) at early time, there is a circular radial flow in a vertical plane perpendicular to the Well, and (2) at late time, there is a horizontal pseudoradial flow. Each type of flow is associated with a semilog straight line to which semilog analysis has to be adapted. The horizontal pseudoradial flow takes into account a pseudoskin depending on system geometry, which is a priori defined and estimated. Practical time criteria are proposed to determine the beginning and the end of each type of flow and to provide a guide to semilog analysis and well test design.

We study the behavior of uniform-flux or infinite-conductivity horizontal wells, with wellbore storage and skin. The homogeneous reservoir is infinite or limited by impermeable or constant-pressure boundaries. A method is also outlined to transform all our solutions for homogeneous reservoirs into corresponding solutions for double-porosity reservoirs.