bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of a Field Surface and Production Network With a Reservoir Simulator
Authors: Hepguler Gokhan , Barua Santanu , Bard Wade
Published: December 2007

Reservoir simulation studies allow engineers to identify development strategies that can maximize the economic recovery of hydrocarbon resources. During the life of a field, the reservoir engineer confronts numerous decisions about the placement and operation of wells for production or injection. Traditionally, engineers evaluate the costs and benefits associated with competing development strategies by using reservoir simulation tools in different scenarios. The numerical reservoir simulator is used in forecasting recovery of reserves under existing production schemes and in evaluating the effects of changing operating conditions. This approach limits the overall benefit of a field study because it does not consider the effects that flows in wellbores and surface facilities have on the economic performance of the recovery programs. Yet, the costs of compression, separation, fluid injection, or water treatment can have a significant effect on the success of production strategies. When the goal is to identify an optimal hydrocarbon-recovery scheme, a compelling case arises for the computational integration of subsurface- and surface-simulation technologies.

In this paper, we discuss an integrated computational solution for management of reservoir-production strategies and field development. The approach is implemented by coupling a reservoir simulator (Eclipse) with a surface and production network simulator and optimizer (Netopt). Parallel Virtual Machine (PVM) interface provides the coupling communication mechanism that integrates the two simultaneously running simulators. At each timestep, the network simulator and the reservoir simulator provide a consistent integrated solution after rate and pressure convergence is achieved within a predetermined tolerance.
Comparing Single-Point Pressure Buildup Data With Reservoir Simulator Results
Authors: Earlougher Robert C.
Published: December 2007

Matching simulator results with historical reservoir data is an important part of a numerical reservoir simulation study. A good match is generally interpreted as indicating the validity of reservoir data used in the simulation and as justification for predictions of reservoir performance. One common matching technique is to compare simulator-calculated pressures with observed pressure data. Ideally, pressure data from observation wells (never produced or injected into) would be used for such matching. Unfortunately, such data are rarely available. Generally, most reservoir pressure data come from relatively short-term pressure data come from relatively short-term pressure buildup tests. Occasionally, only one pressure is pressure buildup tests. Occasionally, only one pressure is reported, even though the well may have been shut in for days or weeks. This note presents a method for comparing this kind of pressure data with simulator calculations. To keep simulation costs reasonable, reservoir simulation studies usually use 30- to 90-day time steps. Since pressure buildup tests normally last only a few days, it generally is not practical to include them in simulation runs. Thus, simulator results do not directly provide pressures for comparison with buildup-test pressure. Van Poollen et al. present a method for comparing observed pressure buildup data with simulator-calculated node pressure (not simulator calculated well pressure) for the time step during which the buildup test was run. This node pressure should agree with observed buildup pressure at a buildup time of

...........(1)

where

= buildup time at which buildup pressureshould be compared with nodepressure, hours= porosity, fraction= total system compressibility, psi= grid size, ft= total system mobility near the well, md/cp.

Total compressibility, ct, and total mobility (k/u)t, are defined by Matthews and Russell." Eq.1 applies to a well in the center of a square node and assumes that the semilog buildup plot (shut-in pressure, Pws, vs log of shut-in time, log t) is linear at t*. If this semilog plot is not linear at t*, the linear portion of the plot should be extrapolated to t*. The pressure att*, taken from the semilog straight line (extrapolated if necessary) should be compared with simulator-calculated node pressure. If the complete buildup curve is not available for instance, if only one pressure is observed - Eq. 1 cannot be used. In this situation, however, we can calculate a pressure to compare with simulator-calculated node pressure.

.............(2)

P. 711
The Pumpability of Clay-Water Drilling Fluids
Authors: Havenaar I.
Published: December 2007

Various methods have been proposed in the literature to calculate the pressure losses in drill-pipe and bit-nozzles, i.e., those parts of the mud-circuit where the largest pressure-losses occur. Very few data, however, are available to check the validity of these proposals.

Presented in this paper are the results of pumping experiments with clay-water drilling fluids of different specific gravities and different laminar flow-properties (differential viscosity and Bingham yield value), using pipes of different diameters. In addition, a series of measurements on bit-nozzles is discussed.

Two main conclusions may be drawn from this work for the flow through pipes.In the laminar flow region pressure losses can be calculated from the differential viscosity and Bingham yield value of the mud.In the turbulent flow region pressure losses can be calculated with good approximation from a viscosity term which is determined by the volume fraction of the dispersed phase.

Calculations making use of laminar flow properties may lead to erroneous results. The effect of temperature on the pressure losses in the case of turbulent flow can be calculated from the change in viscosity of the dispersing medium, i.e., water.

The main conclusions determined for the flow through bit-nozzles are that for flow conditions prevailing in the field, the pressure-drops in bit-nozzles are independent of the laminar flow properties of the mud. They are solely determined by the density of the mud and the geometry of the nozzle.

Introduction

The last decades have witnessed a steady increase in the depth of oil wells. This is illustrated by the increase in the drilling depth record in the USA from 8,046 ft in 1927 to 21,482 ft in 1953. This increasing depth, together with the experience that high rates of mud circulation and high fluid velocities in the bit-nozzles enhance the rate of drilling, has emphasized the importance of selecting suitable mud-pumps when starting the drilling of a deep borehole.

For such a selection it is necessary to be able to calculate the pumping pressures necessary to obtain the required circulation rates. The main part of the pressure-losses in the mud circuit occur in the drill pipe and the bit-nozzles. Various methods have been proposed in the literature to calculate the pressurelosses in the drill pipe. These methods do not all lead to the same results, and at the time this investigation was started insufficient basic data were available to check their validity. Moreover, to our knowledge, no data are available at all on the effect, if any, of the flow-properties of the mud on the pressure-losses in bitnozzles.
Bridging the Information Gap Between Operations and Engineering
Authors: Dunham C.L.
Published: December 2007

Advances in computer and communications technology have often been cited to justify greater consolidation of staff functions. This consolidation, however, tends to widen the information gap between Operations and Engineering. That trend must be reversed, and the gap can be bridged by applying the latest developments in the very technology that caused the problem to begin with. problem to begin with. The Information Gap What Is It?

The information gap between Operations and Engineering is a communications gap. It is a failure of Operations to gather and communicate pertinent, timely information to Engineering. It is a failure of Engineering to formulate and communicate relevant, timely designs and operating guidelines to Operations. It is a failure of each group to define clearly its information needs to the other. It is a failure of each to understand fully the information needs of the other.

Why Does It Exist?

The old saying, "Out of sight, out of mind," describes one reason why the gap exists. Following are some other reasons:

1. The time lag before information reaches the field or central office makes the information outdated.

2. The operator's priorities often allow him little time to worry about the content or the accuracy of the information.

3. The engineer's priorities often involve him in other projects for extended periods during which he ignores the field.

4. The volume of data generated by the fields can overwhelm central clerical staffs.

5. A lack of adequate feedback causes engineering recommendations to seem irrelevant; as a result they are ignored by personnel in the field.

Why Should It Be Bridged?

All of the causes of the information gap can be surmounted - and occasionally they are, when special problems arise-by personal visits or telephone calls. problems arise-by personal visits or telephone calls. However, efficient operations require continual, routine solutions to the information problem. When information is required, either in the field or in the central office, it must be available. So long as the gap exists, there is much important information that is never transmitted, hence never used; this can lead to a continuing spiral of poor decisions and inefficient operation.
A Model for Events Occurring at Random Points in Time and an Example Application to Casing Failures in Cedar Creek Anticline Wells
Authors: Chesnut Dwayne A. , Goldberg Bernard
Published: December 2007

A familiar example of the "Poisson Pure Death Process" is the phenomenon of radioactive decay. It contains a single parameter, λ, which assumes specific values for each distinct unstable nucleus. Rather surprisingly, data on casing failures caused by salt-flow loading in Cedar Creek Anticline wells are also consistent with this model. This analysis is presented in the hope that other complex failure processes, such as breakdown of sand consolidation treatments, might also exhibit the same statistical behavior. In that case, this model could provide a useful tool for evaluating the economic consequences of such failures.

Data for one homogeneous group of wells are used to test the model and to determine λ for the group. The fit is quite good, and the data analysis techniques illustrated should prove useful to anyone attempting to apply the model under the usual condition of small sample size. An analysis and example show how the model provides a basis for deciding when to exercise preventive maintenance and which remedial alternative is most economical.

Introduction

Many types of complex physical phenomena are described quite accurately by a probability model known to mathematical statisticians as the "Poisson Pure Death Process." A familiar example is the phenomenon of radioactive decay. One cannot predict the precise moment that a given atom of a radioactive element will disintegrate. However, the Poisson model does allow one to calculate the probability that disintegration will occur within any time period of arbitrary duration. This model contains a single parameter, λ, which may be regarded as the average number of disintegrations per unit time when a large number of individual atoms are observed. This parameter has a different value for each radioactive element. Thus, its value depends upon physical details such as the chemical species involved, but the mathematical form of the probability law is the same for all radioactive elements.

The model also applies to other problems in which events occur at random times, especially when the physical phenomenon depends on many variables. In this paper, the model is applied to part of the data available on casing failures in Cedar Creek Anticline wells. The failures show up as complete or partial collapse of casing within salt beds at depths of 5,000 to 6,000 ft in most of Shell Oil Co.’s Cedar Creek Anticline fields.
Field Processing, Gathering and Transporting Sour Natural Gas at High Pressures From Pine Creek, Alberta
Authors: Frye C.C. , Becker H.W. , Masuda A. , Deugau A.V.
Published: December 2007

Natural gas containing 25.65 per cent hydrogen sulfide and 4.75 per cent carbon dioxide is gathered from eight wells and transported 26 miles at a flow rate of 160 MMcf/D and at operating pressures of from 2,200 to 1,800 psig. Dry desiccant dehydrators at each wellsite maintain the dew point of the gas below 17F. Telemetering facilities permit control of field operations from a central instrument console. Corrosion control measures, design considerations and material specifications pertaining to these special conditions are discussed.

INTRODUCTION

Natural gas containing 25.65 per cent H2S and 4.75 per cent CO2 is produced from the Pine Creek field, Alta. It is dehydrated at wellheads, gathered at 2,200 psig and transported 26 miles to the Windfall field where it is delivered to the inlet of, injection compressors at 1,800 psig. The daily average volume of gas transported is 160 MMcf. The project is believed to be unique in its combination of percentage of hydrogen sulfide, operating pressure and transportation distance. This paper describes the project and presents details of some of the design features, corrosion control program and centralized automatic operational control.

The Pine Creek field project is one phase of a joint operation of two fields - the other being the Windfall field. The two fields lie about 30 miles north of Edson, Alta. and 20 miles west of Whitecourt, Alta., respectively, as shown on the map (Fig. 1). They are owned by the same interests and operated according to a plan for maximum economic recovery of products. The Windfall Leduc D-3 reservoir contains a rich condensate-bearing gas containing 15.5 per cent H2S. The gas from the Pine Creek field contains only very small quantities of butane and heavier products. The Windfall reservoir is being cycled to obtain maximum condensate recovery using gas from the Pine Creek field as the displacing fluid, while producing the residue sales gas for both fields from the Windfall field.

The Pine Creek field development and gas-gathering facilities are shown on the map (Fig. 2). The producing formation is the Leduc D-3 reef at a depth of 11,300 ft. The original reservoir pressure was 4,590 psia at 7,400 ft subsea and the temperature is 245F. Eight wells are equipped with dry desiccant dehydrators with the following capacity ratings: three at 35 MMcf/D; three at 20 MMcf/D; and two at 10 MMcf/D.

WELLHEAD EQUIPMENT

Dry desiccant dehydrators were designed to reduce the water content of the saturated wellhead stream to 2.5 lb of water/MMcf at 2,000 psig. This specification was necessary to prevent hydrates and corrosion forming in the pipeline which will operate at temperatures as low as 20F. A typical flow diagram is shown in Fig. 3, and Fig. 4 is a photograph of one of the wellhead installations. Some of the design details given below are subject to modification in the field.
Impressions of the Russian Oil Industry
Authors: Smith Noyes D.
Published: December 2007

In 1959 the USSR produced approximately 1 billion bbl of crude oil, which corresponds to U. S. production in 1929. In the Soviet seven-year plan, production of petroleum is scheduled to increase to 1.75 billion bbl. The exploration opportunities in the Soviet Union are roughly comparable to those in the U. S. in the late 1920's. With the techniques presently available to them, it appears certain that they will be able to accomplish the exploration objectives of their seven-year plan. In production, the Soviet industry is conservation-minded, maintains pressure by water injection and plans production of a reservoir on 4 per cent a year. Many of their current fields have multiple horizons which have not yet been exploited. Soviet refineries are difficult to compare to those in the U. S. because the interest is primarily in distillate production rather than in gasoline production. Their equipment is inferior to modern U. S. equipment but is satisfactory for their present demands. The Soviet Union is presently short of pipeline and storage facilities, but a special effort has been undertaken to supply these. The Russians expect to increase their exports of crude petroleum and products, and it is almost certain that they will accomplish their petroleum industry objectives in the seven-year plan. The author's impression was that the people of the Soviet Union are satisfied with their systems of government and economics and are proud of the progress they have made. The people are very poorly informed about the rest of the world, in particular the U. S. Their living standard currently is much below that in the U. S. and Western Europe, although it apparently has risen considerably since World War II.

Introduction

During the month of Aug., 1960, a group of eight oil men representing various aspects of the petroleum industry in the United States and two technical experts from the U. S. Government visited Russia and its petroleum industry. The delegation was selected by the American Petroleum Institute to represent the U. S. oil industry in an exchange of visits with Soviet petroleum representatives.

JPT

P. 621^
A Trapping Hele-Shaw Model for Miscible-Immiscible flooding Studies
Authors: Claridge E.L.
Published: December 2007

It has been noted previously that Hele-Shaw (parallel-plate) models are better than other types of laboratory models to properly scale down miscible displacements from field size to laboratory size. In most miscible flooding processes, however, the miscible displacement is preceded or followed by an immiscible displacement in which oil or gas is trapped by water, or waterflood residual oil is reconnected by a miscible slug. This trapping and reconnection could not be simulated in a conventional parallel-plate model. parallel-plate model. Now, however, a new version of this type of model has been invented that simulates the trapping behavior of porous rock. Instead of trapping by capillary (surface tension) forces, the new model traps light fluids by density difference (Fig. 1). A model of this type can be used to simulate, for example, the tertiary recovery process in which a solvent slug (e.g., CO2) injected in a waterflooded oil field and then followed by another water drive. The particular model devised for this purpose was made of 3-in. thick, 14-in. square plates purpose was made of 3-in. thick, 14-in. square plates of Plexiglas. The top plate contained 596 pairs of 1/40-in.-diameter holes, 112 in. apart at the base, and meeting 3/4 in. deep in the plate. Vent holes 1/16in. in diameter were drilled from the other side of the plate to the junctions of these pairs. The 12- x 12-in. square perforated region was supplied with wells in a nine-spot pattern, and was sealed around the periphery by an O-ring in a rectangular groove. The plates were held a fixed distance apart by shims and bolts outside the O-ring. A typical plate spacing was 0.01 cm. After the model was filled with liquids and air was forced out of the trapping holes, the vent holes were plugged with rods.

P. 255
Displacement of Oil From Porous Media by Miscible Liquids
Authors: Offeringa J. , van der Poel C.
Published: December 2007

The report describes scaled model experiments on the recovery of oil from porous sands by the injection of miscible liquids [solvents] and the subsequent recovery of the solvents by water flooding. Special attention has been paid to the scaling problem.

Scaling rules are deduced and their correctness is checked by carrying out experiments in tubes of various sizes.

Data are submitted on the effect of the viscosity ratio oil-solvent on the efficiency of the displacement process, the viscosity ratio varying from 1.5 to 5,000.

Breakthrough recoveries obtained when flooding with kerosene as a solvent, are equal to those obtained in water flooding at the same viscosity ratio, indicating that the phenomenon of viscous fingering is decisive. After breakthrough, however, flooding with a miscible liquid becomes much more efficient than a water flood and this is more pronounced as the viscosity ratio oil-solvent is higher.

Although high oil recoveries are obtained and most of the solvent in the sand can be recovered by a subsequent waterdrive, a straight flood with miscible liquids does not appear economically attractive because of the large quantities of solvent required. Therefore, a circulation process is introduced, the features of which are described in this paper. Though by means of this circulation process the amount of solvent required can be drastically reduced, the process is not yet economic.

Scope of the Investigation

The recovery efficiency by water flood of oils of viscosities exceeding 50 cp is low. As interest in production of these highly viscous oils is growing at the moment, it was considered worthwhile to gain basic information on the feasibility of first flooding such oils with a low viscous miscible liquid [solvent] and subsequently producing the latter in a conventional way, e.g. by water flooding. The method has the obvious drawbacks that return on the investment is delayed until water flooding has begun and that it requires the investment of a more valuable product to produce a less valuable one. On the other hand, it may be expected that the displacement of one liquid by another is more efficient when the two liquids are miscible than when they are immiscible. As laboratory data on this point are scanty, the present investigation seemed justified.
The Economics of the International Petroleum Industry
Authors: Chapman A.H. , Duce James Terry
Published: December 2007

Introduction

The petroleum industry's operations not only affect the lives of all of us here, but also play a major role in shaping the economy and influencing the political life of every nation in the world. We find ourselves today face-to-face with enormous responsibilities at home and abroad. In this paper the writers will review some of the dangers and pitfalls which the industry has overcome in the past, and, even more important, take a good look at the future - particularly the long term future of supply and demand, and the political factors which underlie them.

Thirty-five years ago we were gravely concerned over our vanishing oil resources. At that time one of the pundits of the economic world recommended to his friends that they sell their oil stocks for the reason that the industry would soon have no raw material with which to work. At the same time, a Kansas professor strongly advised against "senseless joy-riding," as he considered it a waste of precious natural resource which, in his opinion, should only be sold at a very high price as, of course, a measure of conservation. However, our Kansas professor felt also that the way to keep the price high was for the states to siphon-off the profits in high taxes, and he mentioned taxes of a dollar a barrel.

Our first and greatest concern then was the scarcity of the basic raw material upon which the industry lived. Eugene Stebinger, then chief geologist of the U. S. Geological Survey, had estimated the possible world reserves at under 30 billion bbl. MidContinent crude sold for over $31 bbl. Since that time we have consumed some 50 billion bbl and today our forward supply picture has never been more promising.
Dual Pumping With Five Strings of Tubing
Authors: Edwards F.C.
Published: December 2007

Introduction

Dual pumping, and its accompanying problems, has been a subject of continuing interest to the oil industry. From an economic standpoint, a substantial savings in drilling and equipment costs can be realized by the use of dual completions.

The problems encountered in the design and installation of the dual pumping equipment in this particular field were no different from those likely to be met in any field where dual pumping might be considered. For successful installations in this field the objectives of the designers were:To utilize conventional hydraulic pumping equipment, thereby standardizing all pumping operations.To obtain high pumping efficiencies from both zones by completing the upper zone with no packer and venting the gas in the lower zone from beneath the picker to the surface.To pump each zone independently without communication between the two as required by the Oil and Gas Division of the Texas Railroad Commission.

These three objectives have been accomplished and all presently-installed dual pumps of the type to be discussed are operating successfully. This type of dual pumping completion eliminates many of the problems encountered with "down the hole" trigger mechanisms. Each zone may be pumped in a conventional manner and both zones can be pumped simultaneously or individually.

Well Completions

Dual pump installations have been installed in the Prentice field and the Prentice 6,700-ft field located in Yoakum and Terry Counties, Tex. The pay zone in the Prentice field is the Glorietta (limestone of Permian Age), at a total depth of approximately 6,000 ft. The pay zone in the Prentice 6,700-ft field is the Clearfork (limestone of Permian Age), at a total depth of 6,700 ft. Most wells in both the Glorietta and Clearfork underwells. Prior to installation of dual pumping equipment in wells in these fields, all wells were twinned, that is a single well was drilled to each pay zone.
Comments on Finding the Most Profitable Slug Size
Authors: Holm L.W.
Published: December 2007

In the Forum, "Finding the Most Profitable, Slug Size" (Aug, 1972 JPT, Pages 993-994), S. C. Jones found that the most profitable slug size for the micellar solutions he investigated was about 3 percent PV for a homogeneous porous system. He concludes that "even smaller slugs should be used with increasingly stratified reservoirs, quite the opposite conclusion from a classical paper on the subject." The explanation Jones gives for using reduced slug sizes in heterogeneous sands is that the oil in the tighter zones costs more to recover than it is worth. On the surface, this explanation seems reasonable. However, these tight zones may contain the major portion of the oil we seek to recover. In any event, I think the conclusion applies only to a limited number of reservoirs. Let me explain why. To begin with, Jones' conclusion that the optimum slug size becomes smaller as the degree of stratification increases is not supported by experimental data. The oil recovery curves presented by Jones for various stratified sands were calculated on the basis of the curve for the homogeneous sand. These calculated curves apply to watered-out, stratified systems in which no communication between zones exists and in which all zones are at or near residual oil saturation. Consequently, they do not include the effects of crossflow or transverse dispersion that occurs between zones of different permeabilities in many porous systems. porous systems. On Fig. 1,* I have plotted Jones' calculated curves for comparison with experimental results (Curve A) that we have obtained from soluble-oil floods conducted in a two-layer, noncommunicating stratified system at high (65 percent PV) oil saturation. The greater slope of the experimental curve indicates that the optimum slug size would not decrease as stratification increases but may remain at about the 3-percent-PV level.

P. 77
Failure of Stream Tube Methods To Predict Waterflood Performance of an Isolated Inverted Five-Spot at Favorable Mobility Ratios
Authors: Martin J.C. , Woo P.T. , Wagner R.E.
Published: December 2007

Failure of Stream Tube Methods To Predict Waterflood Performance of an Isolated Inverted Five-Spot at Performance of an Isolated Inverted Five-Spot at Favorable Mobility Ratios

Introduction

Since their introduction by Higgins and Leighton in 1962, stream-tube methods (STM) have been used by a number of authors to make approximate waterflood and gas flood calculations. The principal justification for the methods is given by Higgins and Leighton, who present excellent agreement between their STM results and the experimental and numerical result of Douglas et al. for a wide range of M values in a repeated five-spot-pattern waterflood. Doyle presents fair to good agreement between STM results and laboratory model results for five-spot and direct line drive well configurations. The basic assumptions of the Higgins-Leighton STM arethat the streamlines are independent of the mobility ratio, andthat Buckley-Leverett theory can be used to calculate the fluid displacement between adjacent streamlines.

The first assumption allows the streamlines to be determined from singlephase flow and to be held fixed as the flood progresses. In their original work, Higgins and Leighton used potentiometric model results to determine the potentiometric model results to determine the streamlines. Other authors, including us, have used analytical and numerical methods involving pressure and stream-function solutions.

Discussion

Fig. 1 presents calculated oil recovery vs displaceable pore volumes injected for an isolated inverted fivespot pore volumes injected for an isolated inverted fivespot pattern for various values of M. pattern for various values of M. JPT

P. 151
Correlation Between Pore Structure of Sandstones and Tertiary Oil Recovery
Authors: Batra V.K. , Dullien F.A.
Published: December 2007

An excellent correlation has been attained between pore structure and additional recoveries obtained in tertiary surfactant floods for 15 different sandstones. A reasonably good correlation exists between the reciprocal of mean neck diameter (as obtained from mercury porosimetry) and the additional recoveries obtained in tertiary surfactant floods.

THEORY AND EXPERIMENT

When conducting laboratory tertiary surfactant floods on a variety of different sands, sometimes great differences are found in the tertiary oil recoveries - the reasons for which are often not well understood. In the present study it has been demonstrated that, for the set of conditions used, the observed differences in tertiary oil recoveries could be correlated with the pore structure of the samples.

The problem of how pore structure might influence tertiary oil recovery has been discussed by Dullien et al. In the present study, 15 outcrop sandstones have been successfully ranked on the basis of their pore structure in the order of increasing amounts of tertiary recoveries expected under identical conditions of flooding.
How To Diagnose a Thief Zone
Authors: Felsenthal Martin
Published: December 2007

Calhoun presented a classical method for determining the time required for tracer-tagged liquids to flow from injection wells to producing wells. This method can also be used for evaluating the permeability of the most conductive layer of the formation. This layer may turn out to be a "thief" zone that ought to be closed by subsequent remedial action. Calhoun's method of analysis unfortunately is time consuming because it involves either a graphical integration or an approximation using a summation of terms. A simpler method was therefore developed that achieves the same purpose with much greater speed and with sufficient accuracy. The method is based on a model of two radial-flow regimes illustrated in Fig. 1. Radial flow emanates from the injection well, which acts as a "source," and converges in the producing well, which acts as a "sink" . A unit mobility ratio for the displacing and displaced phases and a piston-like advance of the tracer-laden liquid are assumed. The derivation of the equations starts with the familiar radial-flow and material-balance relationships, which are modified so that they apply to the highest-permeability layer of the formation. Thus,(1)0.00707 k1h1 (p/2) qf = ln(d/2rw)(2)2 2 Wif = 0.1781 (r1 - rw) h1 (1-Sor),

where Subscript 1 refers to the high-permeability layer or "thief" zone and(3)f = k1h1/total kh of formation, q = injection rate for well, B/D, Wi = cumulative injection in well, bbl, ri = radius of tracer front in high-permeability layer

Eqs. 1 and 2 are combined through the relationship Wi = qt and the resulting equation is solved for t', the time required for the flood front to travel half way from the injection well to the producing well. The desired time, t, for first arrival of tracer-tagged liquid at the producing well is then set equal to 2 t'.

P. 839
First Jack-Up Production Platform in the North Sea
Authors: Cheng Aylmer P. , Kelewer Jerry F.
Published: December 2007

Introduction

A jack-up gas production platform by Amoco International Oil Co. was installed in Aug. 1972 in 75 ft of water in the Leman field, British North Sea. It was the first jack-up production platform installed in the North Sea. production platform installed in the North Sea. The main advantage of using the jack-up platform rather than the conventional template-type platform is that all production, storage, and living facilities can be installed, tested, and checked out in the fabrication yard before it is removed for installation. As a result, considerable expensive offshore work is avoided, and more important, much less time is required to commission the production facilities and begin operation.

Design

Basically, the platform is designed as a flat-bottom, flush-deck barge with vertical sides and raked ends. Between the flat bottom and flush deck, the barge is subdivided into thirty compartments by six athwartships full scantling bulkheads, four longitudinal bulkheads and several division bulkheads. The barge is supported by six caissons 71-in. OD and 195 ft long, each extended through a well in the platform. There are three wells on the port side and three on the starboard. The dead weight of the barge and caissons is 3,070 kips. The dry weight and wet weight of the production facilities are 1,550 kips and 1,840 kips, respectively. The soils encountered in the boring to the maximum penetration explored (203 ft) are primarily fine sand. penetration explored (203 ft) are primarily fine sand. A laterally loaded pile computer program was used to develop soil-resistance caisson-deflection characteristics for the caisson design. The design penetration for the six caissons is 55 ft, with a 20-ft-long grout plug placed on top of the natural soil plug. The design analysis was performed with a staticelastic space frame analysis computer program. Stokes' fifth order wave theory was used to generate the wave forces on the caissons. The maximum lateral deflection of the barge under storm condition is 10 in. The natural period of the platform is computed by the Rayleigh method and is found to be 2.5 seconds, which is much less than the period of the storm wave. Thus the dynamic amplification effect is negligible. The limiting angle of roll of the barge under tow was 9.25 degrees, at which position the stress in the caissons would be equal to 80 percent of yield. The draft of the barge is 5.1 ft. The period of roll of barge under tow was calculated to be 4.8 seconds.

Construction

The platform, built in Holland during 1971 and 1972, was constructed in three sections - one each in Amsterdam, Sliedrect, and Rijn. The three completed sections were then assembled at DeGroot and Van-Vliet yard at Slikkerveer and then towed to the DeGroot International N.V. Yard at Zwijndrect.

JPT

P. 323
Production Engineering Aspects of Shannon Reservoir, Cole Creek Field, Wyoming
Authors: Gates C.F. , Brown G.G.
Published: December 2007

Performance of the Shannon Reservoir, Cole Creek field, Wyo., is summarized. Oil has been secured largely by water drive.

Calculated pressure-rate performance based on Hurst's water-drive equation for an infinite reservoir coincides with observed performance. An empirical relationship indicates that the difference in pressure between the perimeter and the oil producing area for a given oil rate by water drive is about proportional to the cumulative oil produced. Calculated future performance, based on Hurst's equation, the pressure difference relationship, and the reservoir oil rate equation, correctly indicated limitations on maximum oil rate which were not apparent before the calculations were made.

Net formation withdrawals have been reduced to about zero by the injection of water in six wells spaced around the perimeter of the field. About three-fourths of the injected water rate merely replaces the former natural water encroachment rate; the remainder supports an increased oil rate.

Productivity indexes are being maintained at a maximum by keeping producing pressures at a high per cent of the bubble-point pressure through the use of "bubble-point pumps" and shut-in casingheads. The maximum efficient rate of the reservoir is automatically produced thereby. Productivity indexes of wells were increased many-fold by shooting with nitroglycerin.

Indicated recovery efficiency is about 33 per cent but ultimately may he higher.

Introduction

Although the Cole Creek Shannon reservoir is relatively small, it is of especial interest to the production engineer for the following reasons:Reasonably complete field data have been secured throughout the 14-year life of the reservoir.The limited natural water drive is being supplemented by water injection.Present installations automatically produce the maximum efficient rate.The reservoir has behaved largely according to engineering calculations.There are enough diverse aspects of the reservoir history to warrant intense study.

This paper consists mostly of data and our interpretations of the data. For continuity and completeness the paper repeats some data given by Whitaker and Hoenshell.
Economics of Water Flooding
Authors: Brundred L.L. , Brudred Latham L.
Published: December 2007

Water flooding has progressed from the haphazard experimental stage through numerous phases to a somewhat precise engineering achievement. Unfortunately the economics, which are dependent on so many variables, have not yet lent themselves to particularly accurate interpretations.

Recognizing that technical studies are proceeding rapidly, there still are divergent schools of thought. Regardless of divergences of opinion, the first step in any proposed project is a complete engineering study, evaluated in the light of past experience.

The economics fundamentally boil down to the component parts of the following simple formula: Expected Gross Revenue less The Summation of Computed Acquisition Costs, Costs of Development, and Operating Costs (over the life of the flood) equals Estimated Gross Profit.

Estimated Gross Revenue can be fairly reliable determined from the initial engineering study. Acquisition costs must be based upon the true value of the property and are always subject to negotiation. Development costs are influenced by many factors, but are largely controlled by the depth and the spacing used. They can be estimated with reasonable accuracy once the spacing program has been adopted. Operating costs ]do not lend themselves to ready determination because of the variables involved, but reasonably accurate estimates are possible.

There is no substitute for experience. Approximately seven out of 10 waterflood attempts are failures. It is just as important to determine basic causes of failure as it is to study successful floods. Good floods are widely publicized, the poor ones never. Most of these failures can be attributed to improper engineering, lack of experience, or shortage of working capital.

Engineering and economics are inseparable, and a proposed flood, based on sound engineering, must meet heavy financial demands. While waterflooding is often considered one of the safest of oil ventures, it, too, can be hazardous. "First results" are often long delayed, and pay out is invariable slow.

The conclusion is inescapable that successful waterflooding requires three basic essentials: engineering, experience, and economics.
Design and Operation of Plants for the Preparation of Water for Injection Into Oil Reservoirs
Authors: Watkins J. Wade
Published: December 2007

Both the design of plants in which water is to be treated for subsurface injection and the operation of the plants are important to the success of waterflooding and pressure-maintenance operations. Treating plants should be designed specifically for conditioning of the water or brine to be used in the project. The principal factors to be considered in designing a plant are:characteristics of water to be treated;quality of treated water desired;primary and ultimate capacity of plant;most favorable location of plant site; andtype of plant and equipment that will best serve the purpose.

The operation of an injection-water-treating plant is at least as important as the proper design of the plant and judicious choice of treating methods. The important considerations in operating a plant are:qualifications and training of operating personnel;regularity and accuracy of water analyses;analytical equipment and reagents used; andprecise control of mechanical equipment.

The design of equipment for the various steps in the treating process are discussed independently in this paper. Criteria for the optimum characteristics of treated water also are given. It is concluded that a particular effort should be made in designing and operating an injection-water-treating plant to minimize corrosion, prevent plugging, and improve the water as a flooding medium.

Introduction

The choice of design for a plant in which water is to be treated for subsurface injection and the method of operating that plant determine to a large extent the success of an injection project. The efficiency of water treatment and, consequently, the quality of the treated water, will depend directly upon the kind of equipment employed in the plant and the manner in which it is used, as well as upon the chemicals used for treatment. The factors involved in the design and operation of a plant for treating a particular water to the best advantage are discussed in this paper.
Preparation of Water for Injection Into Oil Reservoirs
Authors: Torrey Paul Dwight
Published: December 2007

Introduction

The most important item in the injection of water into oil reservoirs is the water supply itself. Not only is a certain source of supply essential, but the quality of the water is also of great importance.

Nature rarely provides chemically pure or bacteria free water in any substantial quantities. Water, whatever its source, ordinarily contains a variety of impurities which may be inorganic, organic, or both. Even though these impurities may be present in very minute quantities, their existence must be recognized in almost every water injection system. However, the taste, the odor, or the toxicity of the water, important items where water is to be used for human consumption, are relatively unimportant in oil field use. The two principal problems connected with the use of water to improve oil recovery are possible reaction with the reservoir and its contents, and whether the water will cause destruction of surface and subsurface equipment by corrosion.

In the early days of secondary waterflooding operations in the Bradford and Allegany fields, little attention was given to the preparation of water, for an ample supply of fresh water of good quality was available from shallow aquifers and from surface streams. In the Southwest and particularly in Texas no such fortuitous conditions exist. In most parts of Texas, suffering as they have from recurring and progressively ruinous years of drought, the oil industry will have little call on the limited supplies of fresh water, and therefore must resort to water resources of inferior quality. In almost every case such waters will require some form of treatment before they will be suitable for injection into oil reservoirs. Consequently, the importance of proper conditioning of water to be used for such purpose is now rather generally accepted.

The quantity of water that will be required for complete secondary recovery and pressure maintenance operations in the oil fields of Texas can be estimated in amounts of almost astronomical proportions. Studies recently completed by the Texas Petroleum Research Committee indicate some 10.5 billion bbl of oil that is physically recoverable by injection of water into the reservoirs. It is roughly estimated that approximately 15 billion bbl of water will be required for this purpose. The water that will be available for these operations will have to come largely from subsurface salt water-bearing formations and probably to some extent from the open sea.
Geothermal Energy Potential in Northern Appalachia
Authors: Rieke Herman H. , Skidmore Duane R.
Published: December 2007

Introduction

Rising domestic energy needs in the face of limited supplies have led to various estimates of total energy consumption through 1985 and beyond. Increases in domestic energy production sufficient to meet demand by 1985 appear unlikely if energy sources are limited to fossil or nuclear fuel. The intent of this discussion is to delineate and evaluate the geothermal resource base of northern Appalachia, which comprises portions of the states of New York, Pennsylvania, North Carolina, Maryland, Virginia, Ohio, and West Virginia. Total development of geothermal resources in this region could provide additional amounts of energy for electrical provide additional amounts of energy for electrical power, commercial and process heat, valuable power, commercial and process heat, valuable minerals, and desalinated water for the eastern U. S.

Geothermal Resource Base

Determination of the resource base is supported by the assignment of quantitative values to the following parameters:geothermal gradient,heat flow parameters:geothermal gradient,heat flow in the subsurface, andheat capacity of the rocks.

It should be realized that even in the most intensely investigated geothermal areas but few of these values are known, and then often only within an order of magnitude.

Geothermal Gradients

Fig. 1 illustrates a re-evaluated distribution of geothermal gradient values for northern Appalachia. Unfortunately, these data show only a broad range in the variation of these values (0.7 degrees F/100 ft to 2.1 degrees F/100 ft). Localized high and low gradient values could readily occur within the contours of the map.

Heat Flow

In-situ heat transfer measurements provide information about the amount of geothermal energy available in the region. The global average measured heat flow is approximately 1.5 HFU (1 HFU = 1 cal/cm2-sec), whereas the average heat flux in the Appalachian system has been estimated to be 1.3 HFU. Local thermal resistivities were re-estimated for various lithological units in Appalachia. Horizontal heat transfer between adjoining rock bodies was ignored. Fig. 2 illustrates the variation of the regional heat flux, which ranges from 0.6 to 1.5 HFU. One area bordering southern West Virginia and western Virginia contains a mixture of anomalous high and low heat flux values. Further field work must be done to resolve the implied geological problem.

Geothermal Energy Potential

The sensible heat stored in the sedimentary rocks was calculated with the following equation:

Q = C, (1)

JPT

P. 1005