bluuebunny/crossref_metadata_2025 huggingface dataset:
The Introduction of the Microchanneling Phenomenon to Cyclic Steam Stimulation and Its Application to the Numerical Simulator (Sand Deformation Concept)
Authors: Ito Yoshiaki
Published: December 2007

Historically, a vertical or horizontal fracture is believed to be a main recovery mechanism for a cyclic steam-injection process in unconsolidated oil sands. Most current computer models for the process are based on the fracture concept.

With the postulated sand deformation concept, on the other hand, the injected fluid is able to penetrate the unconsolidated oil sand by creating microchannels. When the pore pressure is reduced during production, these secondary flow channels will collapse totally or partially. Condensed steam tends to sweep fluids where the bitumen had been heated and imparts mobility as a result of the injected hot fluid.

Flow geometry of the new concept is described in this paper. The physical differences between the sand deformation zone and the no-deformation zone are also investigated. The three major differences between these two zones are porosity change, pressure level, and energy and flow characteristics resulting from the existence of microchannels.

All these modifications were incorporated successfully into a conventional numerical thermal simulator. The new model provided an excellent match for all the field observations (steam-injection pressure, oil-and-water production rates, fluid production temperature, downhole production pressure, and salinity changes) of a steam-stimulated well in an unconsolidated oil sand. The study indicates that the most important phenomenon for in-situ recovery of bitumen is the one-way-valve effect of the microchannels, which are opened during injection and closed during production.
Influence of Temperature and Pressure on Asphaltene Flocculation
Authors: Hirschberg A. , deJong L. N. J. , Schipper B. A. , Meijer J. G.
Published: December 2007

A thermodynamic liquid model has been developed to describe the behavior of asphalt and asphaltenes in reservoir crudes upon changes in pressure, temperature, or composition. Asphaltene solubility properties used as input to the model may be obtained from titration experiments on tank oil. High-pressure flocculation experiments confirm the potential of the model. The model appears to be well applicable to conditions at which asphaltenes are associated with resins. The model may be used to identify field conditions where asphalt or asphaltene precipitation will occur.
Behavior of Microemulsions Under Compression
Authors: Rossen W. R. , Kohn J. P.
Published: December 2007

Compression to reservoir pressures can alter microemulsion phase behavior, on which the success of microemulsion-based EOR processes depends. For convenience, however, phase behavior studies usually are conducted at atmospheric pressure. Extrapolating phase behavior data from atmospheric to reservoir pressures requires the volumetric properties of each phase under compression, including the isothermal compressibility as a function of pressure and composition.

Two topics are addressed here. First, compressibility data up to 16 MPa [2,300 psi] are presented for several systems of oil and water with surfactants and protosur-factants and the data are fit to simple models for pressure and composition dependence. The pressure dependence fits the Tait equation in this pressure range; selected high-pressure data indicate how the compressibility deviates at much higher pressures. To within the resolution of the data, the composition dependence is linear in volume-fraction composition; moreover, the effective compressibilities of oil and water in solution appear to be near their pure-component values. More data are needed to verify and determine the exact dependence.

Second, a simple compressibility cell is described that allows both rapid determination of compressibility and direct determination of the phase boundary in pressure. Both phase separation and coalescence of distinct phases with increasing pressure was observed in microemulsion systems, although the phase boundaries in pressure for these systems were not mapped out systematically. The effect of dissolved gases such as methane, which can affect microemulsion phase behavior at high pressures, is not addressed here.
An Integrated Design of Lease Programming and Custody Transfer Facilities
Authors: Wasicek J.J. , Kleppinger K.B. , Grovenburg W.W.
Published: December 2007

Introduction

The Adena J sand field is the largest field to date in the Denver-Julesburg Basin (Fig. 1). This field is located in Morgan County, Colo., approximately 12 miles south of Fort Morgan. The discovery well in the Dakota J sand was drilled in Nov., 1953. By late 1954 initial development was completed with the drilling of 166 oil wells and 15 gas wells. Early in 1954 the operators recognized the advantages of unitization and committees were organized to conduct the necessary studies. On Jan. 1, 1956, a large portion of the field was unitized with The Pure Oil Co. named as Unit operator. Nine months later additional leases were brought into the Unit. All but three of the J-sand wells in the field are now participating in this Unit.

Early in Feb. 1957, plans for a pressure maintenance program were completed. In July, 1957, water injection was started into a line of wells along the gas-oil contact. This plan of water injection requires only a portion of the wells presently completed in the field to produce the reservoir. Conventional production operations under this pressure maintenance program would have required extensive tank battery relocation, and in addition would have required an elaborate produced water gathering system. An economic study of various producing operations led to the selection of automatic custody transfer equipment and well supervisory control equipment.

Studies revealed that the most desirable system should include one central treating plant and custody transfer station. Distances involved were too great to permit each well an individual lead line to a central station, or to provide supervisory well control from one point. To overcome this problem it was decided to control the wells from stations spaced through the field. Production arriving at each station could be transported to the central treating and custody transfer station through an oil-water gathering line. It became readily apparent that three major problems had to be solved in the system design.
Improved Wireline Cementer Developed to Cope With Water Shut-Off and Channeling Problems
Authors: Briggs George E. , Porter Weldon L.
Published: December 2007

A new wireline cementing tool is described, giving results of surface, subsurface and field tests. New applications and field performance results are presented.

A completely new tool has been developed after extensive testing of the existing tool pointed out certain inadequacies. In order to widen its applications and obtain more predictable results, efforts were directed toward:increasing displacement,eliminating tool movement,obtaining a more satisfactory packer seal,minimizing cement contamination,retaining pressure for a prolonged period of time, andequalizing pressures following the squeeze.

Surface, subsurface and field testing led to still other modifications in the equipment.

In field work to date, the tool has been used almost exclusively in water shut-off problems. The major portion of field work has been in squeeze cementing perforations and a portion thereof.

Field testing in various areas under various well conditions has indicated that predictable results in water shutoff problems can be effected economically with small quantities of cement.

Introduction

Following introduction of the first model of the wireline cementer into the Mid-Continent area in Jan., 1952, field results were closely followed and scrutinized. These results indicated that bottom-hole plug-backs apparently offered no problem. However, in squeezing perforations, the squeeze frequently failed if the cement plug was to be drilled or if the wells contained mud.

These results suggested inadequate displacement of cement into the perforations and contamination of the slurry.
Evaluation of Normalized Stone's Methods for Estimating Three-Phase Relative Permeabilities
Authors: Fayers F. J. , Matthews J. D.
Published: December 2007

This paper examines normalized forms of Stone's two methods for predicting three-phase relative permeabilities. Recommendations are made on selection of the residual oil parameter, Som, in Method I. The methods are tested against selected published three-phase experimental data, using the plotting program called CPS-1 to infer improved data fitting. It is concluded that the normalized Method I with the recommended form for Som is superior to Method II.
An Evaluation of Diffusion Effects in Miscible Displacement
Authors: Handy L.L.
Published: December 2007

Introduction

The development of a theory for miscible liquid displacement requires evaluation of the variables which affect growth of the mixing zone between solvent and displaced oil. Factors which appear to be important are individual fluid viscosities, viscosity ratios, flood rate, fluid densities, flow characteristics of the porous medium and molecular diffusion coefficients of the fluid components. The primary purpose of this paper is to evaluate diffusion effects.

Theoretical treatments to date have been limited to floods for which the viscosity ratio is one. Two principal theories have been proposed. Von Rosenberg adapted for porous media a theory derived for capillary tubes by G. Taylor. In this theory molecular diffusion perpendicular to the direction of flow is a primary factor in sharpening the flood front. Slow floods give sharper fronts for a given distance traveled than fast floods.

An alternative theory considers miscible liquid displacement as a statistical problem. Diffusion is not an important factor in this theory, but it leads to the same general type of equation as von Rosenberg's. Both theories predict S-shaped concentration profiles with the same dependence on distance traveled. The statistical or "dispersion" theory predicts rate independence, however. To supplement rate studies a direct measurement of a diffusion effect would be helpful in evaluating which of the two proposed mechanisms best describes miscible liquid displacement for one-to-one viscosity ratio systems.

No quantitative theory has been proposed for floods in which a low-viscosity fluid displaces a high-viscosity fluid. It might be anticipated, however, that the extensive fingering observed in floods with adverse viscosity ratios would increase opportunities for an exchange of components between displaced and displacing liquids by a diffusional process. Even if molecular diffusion were not an important mixing mechanism for one-to-one viscosity ratio systems, it could be significant in systems with adverse viscosity ratios.
Federal Offshore Oil and Gas Lease Bonus Bid Rejection Policy: Past and Present
Authors: Lohrenz John , Dougherty Elmer L.
Published: December 2007

Policy concerning rejection of bids for U.S. government Policy concerning rejection of bids for U.S. government federal offshore oil and gas leases offered to the market recently has been changed. Technical analyses presaging this change are given here. An initial technical assessment of the new policy compared with the old is presented. presented. Introduction

In 1968, the U.S. government began preparing presale estimates of record for offshore oil and gas leases offered to the market. Previously, informal estimates, now not of record, were made, resulting in the rejection of 5.8% of the leases that otherwise would have been issued. After 1968, the rejection rate more than doubled! The policy that led to that rejection rate has recently been changed. The change parallels a previous study and follows that study closely in time. The purpose of this work is twofold. The issues and technical study that underlie the policy change are traced and summarized. Also, technical assessments based on data under the new policy are made.

Fair Market Value and Government Estimates of Lease Value

The presale estimates prepared and recorded by the U.S. government were used to decide which leases to issue and which should have all bids rejected. The objective written in law is that the government should obtain fair market value for leases issued. Under the old policy, these presale estimates were considered necessary "to assure [that] the Federal government receives fair market value for lands leased....."That policy position became an argued issue elsewhere as well as in the previous technical study. Opposite that position was the viewpoint that fair market value is determined only by cash, or equivalent, exchanges between actual willing sellers and buyers. Government estimates, never required to meet that test, could not be considered to affect fair market value. So argued those opposing the old policy position. In March 1983, the U.S. Dept. of Justice issued a statement that more or less administered a coup de grce to the old policy vis-…-vis fair market value and government estimates: "Our position… is that the high bid on a tract will generally represent fair market value for that tract, absent collusion or other irregularities in the bidding process." This Dept. of Justice position is implicit in the new rejection policy.

What Is an Offered Lease Worth?

The next question is obvious. To whom? The answer relevant to rejection policy is the owners of the leases offered. The owners are, of course, the collected citizens. The issue is: what is the value of an offered lease to the collected citizens as owners of that lease? The question can be answered mathematically as follows.

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

JPT

p. 1951
In-Situ Leaching of Crownpoint, NM, Uranium Ore: Part 3—Laboratory Study of Strong Leaching Systems: Sodium Hypochlorite
Authors: Vogt Thomas C. , Strom E. Thomas , Johnson Warren F. , Venuto Paul B.
Published: December 2007

Alkaline sodium hypochlorite (NaOCl) is a powerful and technically effective leaching system for recovering uranium values from refractory uranium ores from Crown-point, NM. Batch and column-pack laboratory tests show that alkaline bicarbonate solutions containing 0.1 to 5.0 wt% NaOCl afford rapid production of uranium from such refractory ore. Ultimate recoveries of 90% and greater were obtained in column-pack tests. The organic carbonaceous matter found was associated intimately with the uranium mineral in some Crownpoint ore trends and appears to shield some of the uranium from contact with a chemically mild leaching system. NaOCl appears to be a strong enough oxidant to attack the carbonaceous matter and to expose trapped uranium mineral species. NaOCl, however, is such a strong oxidant that it was consumed also by reaction with metal sulfides and other gangue minerals present in the ore. Field applications would require appropriate corrosion control, protection of ion exchange resin from NaOCl, and control of chloride ion buildup.
Reinjection of Large Volumes of Produced Water in Secondary Operations
Authors: Dixon Bryan P. , Newton L.E.
Published: December 2007

A study was made of the operating performance histories of a pressure-maintenance and four waterflood projects in the Permian Basin area, where large volumes of produced water have been reinjected into the producing formations. The projects reviewed include a wide range of characteristics:

open and closed water systems, volumes of reinjected water froth 2,200 to 12,500 B/D, sand and limestone formations, depths of 1.300 to 6,750 ft. average permeabilities from 17 to 275 md, bare and protected facilities, and 10- to 50-year project life.

Each project exhibited performance data which indicated that reinjection of large volumes of produced water provides a good source of injection fluid, results in practical and prudent salt water disposal and, in many cases, results in conservation of fresh water for future domestic needs.

Introduction

The increasing difficulty of finding adequate new oil reserves has caused almost every field in West Texas to be reviewed for possible secondary recovery applications. Because most secondary recovery processes use water, the availability and prudent utilization of water are very important to all oil operators. Standard Oil Co. of Texas' production operations in West Texas include numerous water floods, and several of these projects are reviewed and discussed in this paper. The case histories presented cover handling and reinjecting large volumes of produced water. The fields presented, as shown in Fig. 1. include SACROC unit, Howard-Glasscock, North Ward-Estes. Keystone-Colby sand, and South Ward. The combined cumulative primary and waterflood recovery of these fields to Jan., 1965. is 878.8 million bbl. Pertinent reservoir and waterflood data for the Standard of Texas' projects in each field are shown in Tables 1 and 2. Equipment used and materials for construction in each injection system are shown in Table 3. Waterflood performance histories are shown in Figs. 2 through 7. Schematic flow diagrams of the injection systems are shown in Figs. 9 through 13.

SACROC Unit

History and Development

The Canyon Reef reservoir of the Kelly-Snyder field in Scurry County was discovered in Nov., 1948. The field now encompasses some 50,000 productive acres and 1,321 wells. Cumulative field recovery to Jan., 1965, is 322.4 million bbl. The reef, a limestone formation, is a low mound-type structure varying In thickness from 0 to 800 ft. The field was essentially developed by 1951; and, after extensive negotiations, the field was unitized with a unit manager and three segments, each operated by a working-interest owner effective March, 1953. Standard of Texas was designated unit operator on May 1, 1962.

JPT

P. 781ˆ
The Power of Concept
Authors: Parks Mercer H.
Published: December 2007

Introduction

The power of concept is so immense that undertaking to discuss it brings on a feeling of personal inadequacy and of battering at an impenetrable barrier. It is not that readers are intellectually deficient, nor that I have no words directly to the point, but that words, even illustrated by graphs and pictures, are such dull tools of communication that we, as individuals, are almost completely isolated one from the other.

What one word means exactly the same to any two of us?

In the unabridged dictionary "one" itself has 17 definitions.

Complete understanding of one another is actually impossible.

If, therefore, some of the following statements appear dogmatic or demagogic sentimentality, they are not so intended. They are merely awkward words beating at the barrier between us, probing for a crack through which to reach your curiosity, or your desire to understand, and cause you to think deeply of, not merely consider, the subject; for understanding is something no one can give another. It is something each one must achieve for himself.

With this in mind let us ask: Which one of us has done a single thing that absolutely no one else could have done? And how long has it been since each of us fairly burned to be turned loose to do, not one, but a dozen such wonders?

How Long Has it Been?

How long since we read Ivanhoe, Deerslayer, Tom Sawyer, Tom Swift and Tarzan of the Apes, in our imaginations living through unbelievable feats with the young, resourceful character of the moment? In that moment each of us became what we most wanted to be - an individual, unique and distinct from every other individual, and doing something no other individual ever created could do.

Yet today practically all adult Americans settle down to a bread and butter job - practically the same day after day - a job dozens and probably thousands could do just as well. They settle down to sleeping, waking, bathing, and eating with all the mental vigor of a contented cow. Perhaps they show they're "on the ball" at work when the boss is near - but really they do not feel vigorous at all.
Energy From Oil and From the Nucleus
Authors: Teller Edward
Published: December 2007

Editor's Note: Dr. Edward Teller, one of America's foremost nuclear scientists, delivered the following address at a March 4 luncheon held during the Dallas Section's 1965 Symposium on Petroleum Economics and Evaluation. H. B. Renfro, Dallas consultant who served as chairman of the Symposium Program Committee, introduced Dr. Teller to some 400 SPE members in the audience, and subsequently presided over the question-and-answer period which followed the speech.

Introduction

In 1945, we had been told that nuclear energy would become competitive with fossil energy if and when we could produce electricity from the nucleus at a price of 7 mills/kw-hr. We have done this. We are now approaching the point-perhaps we have already reached it-where electricity from nuclear sources can be produced for as little as 5 mills/kw-hr. Nevertheless, we are still not competitive, in spite of the fact that the price for everything else-that is. everything other than energy, from the price of food to the price of a telephone call-has risen by more than a factor of two. What was 7 mills in 1945 should be now, 15 mills. Electricity from nuclear reactors costs 5 mills today, and possibly a little less. This means that the price of energy has come down in the last 20 years by a factor of three. To a great extent, this is the accomplishment of the oil industry. To a smaller extent, it may be considered as an effect of nuclear energy, because I have the sneaking suspicion that the potential and increasing competition of nuclear energy has stimulated the producers and users of oil into more vigorous action. I would now like to discuss the prospects of this competition, but I do not want to restrict myself to this topic. I would like to discriminate between the various areas where competition will have impacts of various kinds. In other words, the question of whether fossil fuels will be replaced by nuclear fuels does not permit a simple "yes" or "no" answer. I also want to talk to you about the cooperation between these two forms of energy and about the human resources which are necessary to make the best cooperation go forward at a reasonable pace.

Application

I believe that nuclear energy will, indeed, become increasingly competitive with fossil energy and will, in some areas, replace it. This, I believe, will particularly be the case where great amounts of energy are needed in a small area. The reason is that the raw material of nuclear energy is cheap and can become cheaper. That competition is not yet as strong as it may become is due to the fact that our technology of nuclear reactors is still in a state of development. In particular, in nuclear reactors the lack of more massive production's being more economical is strongly justified.

JPT

P. 505ˆ
Determination of Average Reservoir Pressure From Build-Up Surveys
Authors: Dietz D.N.
Published: December 2007

DIETZ, D.N., KONINKLIJKE/SHELL EXPLORATIE EN PRODUKTIE LABORATORIUM RIJSWIJK, THE NETHERLANDS MEMBER AIME

A method for determining average reservoir pressure is presented, which is simpler to apply than that devised by Matthews, Brons and Hazebroek. For bounded reservoirs, identical results are obtained if stabilized-flow conditions prevail. The present method yields inferior results in the transient state. The method can, with a slight modification, also be used for water-drive reservoirs.

Introduction

In the method proposed by Matthews, Brons and Hazebroek for determining average reservoir pressure in a multi-well reservoir, the cumulative production (the production time of each well) enters twice: once when the buildup is plotted against In (t + deltat)/deltat to arrive at p*, and a second time when the correction, p*-p is determined with one of the several formulas for differently shaped drainage areas. Once a steady state has been attained, however, the previous production history should be immaterial. The same pressure distribution could have been arrived at after different cumulative productions of the individual wells. In principle, therefore, it should be possible to determine average pressures without referring to cumulative productions. In the following paragraphs an expression is presented for the difference between the pressure in a producing well and the average pressure of its drainage area. Then the build-up time needed to overcome this difference is indicated.

CASE OF A CIRCULAR DRAINAGE AREA AND A CENTRAL WELL PRESSURE DISTRIBUTION BEFORE SHUT-IN

The general differential equation of radial flow (see Muskat," Eq. 10.2) may be written

(1)

In the steady state, the rate of production of the well is equal to the rate of expansion of the fluid contained in the the drainage area; thus

(2)

and therefore, combining Eqs. 1 and 2 we have

(3)

which can be integrated to

(4)

The boundary condition can be introduced as

(5)

so that Eq. 4 can be rewritten

(6)

A second integration gives

(7)

AVERAGE PRESSURE OF THE DRAINAGE AREA

The average pressure can be expressed as

(8)

Substitution of Eq. 7 and integration yields

(9)

BUILD-UP

If Eq. 7 is applied to the wellbore at rw, and if C is eliminated by the combination with Eq. 9, we have for the pressure at the well under steady-state conditions

(10)

After shut-in, and as long as the physical boundaries of the entire reservoir have no influence, the pressure increases according to the well-known expression

(11)

JPT

P. 955ˆ
Determining Bottomhole Pressures in Pumping Wells
Authors: Hasan A. R. , Kabir C. S.
Published: December 2007

The use of the acoustic well sounding (AWS) technique to determine bottomhole pressure (BHP) requires an estimate of the gas-void fraction (fg) in the liquid column of a pumping well annulus. Three correlations relating the annular superficial gas velocity to fg are available for saturated oil columns. These correlations were developed by Godbey and Dimon,1 Podio et al.,2 and Gilbert as reported by Gipson and Swaim.3 Use of these correlations for determining the BHP, either flowing or shut in, involves a stepwise numerical integration often performed by a computer.

This work addresses three aspects of estimating the BHP from AWS data: (1) estimation of the superficial gas velocity, (2) development of analytical solutions for a single-step BHP calculation, and (3) comparison and interpretation of the predicted BHP's by use of the three correlations for the field examples.

A mathematical model, based on the principle of mass balance of the annular, gas phase, is used to determine the superficial gas velocity. This model rigorously accounts for the time-dependent pressure, volume, and the gas deviation factor in the liquid-free annulus.

Analytical solutions are obtained for both the Godbey-Dimon and Podio et al. correlations to calculate the BHP in a single step. These analytical solutions provide a significant improvement over the numerical stepwise integration technique, because a hand-held calculator can be used for the BHP calculations.

The field examples studied indicate that both the pumping liquid column height and the superficial gas velocity play a key role in estimating the gas void fraction—an essential element in calculating the BHP. We observe that only the early-time shut-in pressures are affected by the presence of gas bubbles in the liquid column. Because the bottomhole flowing pressure (BHFP) is dependent on the correlation used to predict the fg, both skin and productivity index calculations are affected. Estimation of the permeability/thickness product and the static reservoir pressure, however, are independent of the fg correlation used.
The Alteration of Rock Properties by Percussion Sidewall Coring
Authors: Webster G.M. , Dawsongrove G.E.
Published: December 2007

Introduction

The use of percussion-type sidewall cores as an aid in detection and evaluation of hydrocarbon shows and in examination of rock properties has become increasingly popular in recent years. Sidewall coring has an advantage over normal bottom-hole coring methods in that the zones may be surveyed with the electric log prior to selection of sample depths. This allows an efficient sampling of all zones of interest, a procedure not possible with bottom-hole coring techniques unless the costly procedure of continuous coring is utilized. Percussion sidewall coring presently provides the most rapid and lowest cost method of obtaining sidewall cores. It has been recognized for some time that certain discrepancies exist between core analysis data obtained from percussion cores and data obtained from other types of core samples. This paper presents existing field and laboratory data that were available to the authors. Several examples of comparative core analysis data obtained from various fields are presented along with photomicrographs of thin sections of conventional and percussion cores. The results of this investigation are presented to throw more light on the possible disturbed condition of percussion sidewall cores.

Sample Disturbance and Fracturing

The principal cause of discrepancy between conventional core analysis data and percussion sidewall core analysis data is believed to be the shattering and re-adjustment of the grains due to the large impact shearing forces produced by mechanics of percussion coring. Figs. 1 through 5 are photomicrographs of thin section slides of formation samples obtained by means of diamond cores, conventional cores, and percussion sidewall cores.
Visualization of a Surfactant Flood of an Oil-Saturated Porous Medium
Authors: Paterson L. , Hornof V. , Neale G.
Published: December 2007

This paper discusses the viscous fingering that occurs when water or a surfactant solution displaces oil in a porous medium. Such floods were visualized in an oil-wet porous medium composed of fused plastic particles. The flow structure changed significantly within the range of capillary numbers between 10−4 and 10−3. The addition of surfactant resulted in narrower fingers, which developed in a more dispersive fashion.
Case History of the Tensleep Reservoir, Torchlight Field, Wyoming
Authors: Willingham R.W. , Howald C.D.
Published: December 2007

The Torchlight field is located on the east side of the Big Horn Basin in Big Horn County, Wyo. Orchard Unit Well No. 1, the Tensleep discovery well, was completed in 1947. The 33 degrees API gravity Tensleep crude was highly undersaturated, and hydraulically contained in the anticlinal reservoir by a tilted water table. After development, fluid producing rate and reservoir pressure declined rapidly. Field performance indicated the reservoir was producing by a limited water drive and would require over 25 years for depletion. Comparisons are made between field producing rates and rates predicted by water influx theory. Predicted rates are 10 to 15 per cent higher than actual rates. The difference is due to reservoir pressure being higher than that assumed in the prediction. Supplemental water injection was started in Oct., 1957, to reduce reservoir life and increase oil rates. Oil response was immediate and reached a maximum rate of 1,785 BOPD in 1959. By Jan., 1965, the reservoir had been essentially depleted after producing 2,774,000 bbl oil. Supplemental water injections have reduced reservoir life at least seven years. Oil recovery by supplemental water injections of 43 per cent of original oil in place will be comparable to recovery by natural water drive. Predicted oil recovery by the Dykstra-Parsons and Stiles methods indicate recoveries of 46 and 50 per cent original oil in place, respectively. However, these two methods assume 100 per cent areal sweep efficiency, and reduction for areal sweep would result in close agreement with actual recovery.

Introduction

The Tensleep reservoir, Torchlight field, Wyo., is nearing depletion by natural water drive and supplemental water injections after producing over 2.7 million bbl of oil. Collection of extensive engineering data during early development permitted thorough evaluation of reservoir properties, early recognition of the producing mechanism and initiation of a water injection program which significantly increased oil rate and reduced reservoir life. Water injections did not influence or change ultimate oil recovery but provided a decrease in operating costs as compared to depletion by natural water influx. The advanced stage of depletion, plus availability of necessary engineering information, permits comparisons between theoretical and actual reservoir performance. The fluids, rocks and producing mechanism of the Torchlight Tensleep reservoir are characteristic of many Rocky Mountain Pennsylvanian Age reservoirs. A review of the history of the Torchlight Tensleep may assist in more efficient operation of similar reservoirs.

History of Development

Torchlight field is located on the east side of the Big Horn Basin in Big Horn County, Wyo. (Fig. 1). Wells were drilled as early as 1904, making Torchlight one of the oldest oil fields in Wyoming.

JPT

P. 1159ˆ
Injection and Energy Recovery in Fractured Geothermal Reservoirs
Authors: Bodvarsson Gudmundur S. , Pruess Karsten , O'Sullivan Michael J.
Published: December 2007

Numerical studies of the effects of injection on the behavior of production wells completed in fractured two-phase geothermal reservoirs are presented. In these studies the multiple-interacting-continua (MINC) method is employed for the modeling of idealized fractured reservoirs. Simulations are carried out for a five-spot well pattern with various well spacings, fracture spacings, and injection fractions. The production rates from the wells are calculated using a deliverability model. The results of the studies show that injection into two-phase fractured reservoirs increases flow rates and decreases enthalpies of producing wells. These two effects offset each other so that injection tends to have small effects on the usable energy output of production wells in the short term. However, if a sufficiently large fraction of the produced fluids is injected, the fracture system may become liquid-filled and an increased steam rate is obtained. Our studies show that injection greatly increases the long-term energy output from wells because it helps extract heat from the reservoir rocks. If a high fraction of the produced fluids is injected, the ultimate energy recovery will increase many-fold.
Factors Contributing to the Ability of Acrolein To Scavenge Corrosive Hydrogen Sulfide
Authors: Kissel Charles L. , Brady John L. , Gottry H. Nancy Clifton , Meshishnek Michael J. , Preus Martin W.
Published: December 2007

Acrolein can function under a variety of conditions as an effective hydrogen sulfide scavenger in oilfield waterflood systems. The scavenging ability is maximized in waters having a pH range of 6 through 8, a total dissolved solids level below 1%, and temperatures less than 149°F [65°C]. At least 4 ppm acrolein is necessary to achieve sufficient reaction of each original 1 ppm hydrogen sulfide. This reaction requires about 2 to 20 minutes, depending on the nature of me system. Although sand, garnet, or diatpmaceous earth filters do not affect the scavenging ability of acrolein, charcoal filters, large tanks, long pipelines, high-temperature Wemcos, and reboilers can produce diminished effects. Further diminished effects also can be produced when incompatible chemicals are used concurrently with acrolein. Some application techniques that can lessen or eliminate these adverse conditions are presented.
The Proper Interpretation of Field-Determined Buildup Pressure and Skin Values for Simulator Use
Authors: Odeh A. S.
Published: December 2007

Scaling factors for the proper application and interpretation of field-determined skin effect and pressure buildup values for use in simulators are derived. Reservoir engineering calculations for the actual well are based on a continuous physical system and the total effective formation thickness. For use with a simulator, the system is discretized, and the cell thickness replaces the total thickness. The scaling factors are to correct for the differences between the two systems. Without the scaling factors, the well inflow equations used in the simulators would calculate an erroneous pressure drop component as a result of the physical skin and the non-Darcy flow effect. In the case of pressure values, an equation is derived that gives the buildup time, ∆t, when the field-measured wellbore pressure becomes, equal to the wellblock pressure in a three-dimensional simulator. This is important for history matching. This paper shows that the pressure-Δt relation is strongly coupled to the skin scaling factor.
Chemical Evolution of a High-Temperature Fracturing Fluid
Authors: LaGrone C. C. , Baumgartner S. A. , Woodroof R. A.
Published: December 2007

Reservoirs with bottomhole temperatures (BHT's) in excess of 250°F [121 °C] and permeabilities of less than 1.0 md are commonly encountered in drilling and completing geothermal and deep gas wells. Successful stimulation of these wells often requires the use of massive hydraulic fracturing (MHF) treatments. Fracturing fluids chosen for these large treatments must possess shear and thermal stability at high BHT's.

The use of conventional fracturing fluids has been limited traditionally to wells with BHT's of 250°F [121 °C] or less. Above 250°F [121 °C], high polymer concentrations and/or large fluid volumes are required to maintain effective fluid viscosities in the fracture. However, high polymer concentrations lead to high friction pressures, high costs, and high gel residue levels. The large fluid volumes also increase significantly the cost of the treatment.

Greater understanding of fracturing fluid properties has led to the development of a crosslinked fracturing fluid designed specifically for wells with BHT's above 250°F [121 °C]. The specialized chemistry of this fluid combines a high-pH hydroxypropyl guar gum (HPG) solution with a high-temperature gel stabilizer and a proprietary crosslinker. The 6fluid remains stable at 250 to 350°F [121 to 177°C] for extended periods of time under shear. This paper describes the rheological evaluations used in the systematic development of this fracturing fluid.

In field applications, this fracturing fluid has been used to stimulate successfully wells with BHT's ranging from 250 to 540°F [121 to 282°C]. Case histories that include pretreatment and posttreatment production data are presented.
Application of the Alternating Direction Explicit Procedure To Two-Dimensional Natural Gas Reservoirs
Authors: Quon D. , Dranchuk P.M. , Allada S.R. , Leung P.K.
Published: December 2007

The alternating direction explicit procedure (ADEP) makes use of the boundary conditions to reduce multi-dimensional problems to a series of one-dimensional problems. The method, previously applied to reservoirs containing only an undersaturated oil, bas now been extended to cover the case of natural gas reservoirs. Although this involves solving a non-linear partial differential equation, application of the procedure is straight- forward and no calculational problems were encountered.

Introduction

There has been a growing interest in formulating mathematical models of petroleum and natural gas reservoirs - models which permit the engineer to examine and evaluate the physical and economic consequences of various alternative production policies. The tremendous reduction in the cost of solving such models in recent years has made possible their use as an almost routine management tool. This reduction is the result not only of improved computer hardware but also of the development of more efficient mathematical techniques. The present paper is concerned with the application of a recently proposed numerical method (ADEP) to two-dimensional gas reservoirs.

STATEMENT OF THE PROBLEM

Given a two-dimensional Region R, bounded by a closed Curve C (Fig. 1) such that the behavior on Curve is known, the differential mass balance for each fluid phase in R, neglecting gravitational effects and assuming Darcy's law for fluid transport, can be written as:

A typical and common set of boundary conditions is given by (1) / = 0 on Curve C where r is the direction normal to Curve C; (2) p is known throughout Region R at some time t; and (3) wf is known for all x, y and t. Physically, this represents the case where the reservoir is bounded by impermeable media, where the initial pressure throughout the reservoir at the beginning of gas production is known and where the production rate at each well is specified at all times. For single-phase reservoirs, the problem is to determine the pressure throughout Region R at all times; for multi-phase reservoirs, in addition to the pressure, the value of the fluid saturation is also required. Since analytical solutions to this equation for the general case are not available, we must resort to numerical integrating techniques, using finite-difference approximations.

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P. 137ˆ
Tubular Corrosion in the West Sole Gas Field
Authors: Gair D. J. , Moulds T. P.
Published: December 2007

Severe corrosion in West Sole tubulars resulted in a fieldwide workover program 4 years after the field was brought on stream in 1967. The optimum solution, balancing cost with efficiency of corrosion prevention, was considered at the time to be the installation of 13% Cr tubing in the upper section of the tubing string. Inspection with caliper surveys has proved the efficiency of such completions in combating corrosion, and the nominal tubing life has subsequently been extended to between 10 and 15 years.
Water Power Fluid for Hydraulic Oil Well Pumping
Authors: Brown F. Barton
Published: December 2007

Water is the obvious answer for a substitute to crude - fresh, sea or produced brine. This paper presents experimental work done on the development of additives to make water suitable for hydraulic pumping. Field testing and recent commercial applications have shown the numerous advantages, practicability and economy of using water as a power fluid.

Introduction

Fluid normally available for power is the produced crude which frequently lacks good lubricating properties, has too high a viscosity at times and contains sand, water, paraffin and other foreign materials. In the early days of hydraulic pumping, only the open system was available and there was an economic limit to improving the quality of the crude power fluid. Development of the free pump gave impetus to use of the parallel string. A natural sequence was the three-string closed system which provided a better, more economical method of cleaning the crude power oil and opened the door to use of other liquids for power fluids. Water is a liquid with a high bulk modulus and is the obvious Substitute for crude.

Search for Additives

In 1958 an intensive experimental program was initiated on the use of water as a power fluid for hydraulic pumping. Low viscosity, lack of lubricating properties, corrosive tendency and bacterial action all combined to make additives a necessity. The additive should provide the desired lubricity, and it should be a corrosion inhibitor, a bactericide, an oxygen getter and a thickener-all mutually compatible. The additives should also be suitable for sea water and oil- field brines. The commercial non-inflammable hydraulic fluids on the market included water glycol, phosphate ester, chlorinated phosphate ester and oil emulsions of 40 per cent water, 55 per cent oil and 5 per cent emulsifier. But the cost of each was prohibitive, running from $40 to $190/ bbl.

In this early work, an oil in water emulsion of less than 2,000 ppm was sought. Over 200 samples of different emulsions were investigated seeking those that would be stable in brine. Further evaluation of oil in water emulsions and film-forming lubricants was carried on in the wear test machine, the laboratory test well and by field tests. In the future, there may be different types of additives available and the choice will be determined by the particular pumping problem involved. Undoubtedly, the selection of additives will revolve around the type of water being used - fresh, very soft, brine or sea water.

Wear Test Machine

In 1933 a wear test machine was built that used reciprocating motion between the wear parts instead of the usual rotary motion. This machine more nearly duplicated the wear action in the bottom-hole pump and has always been useful in evaluation of both materials and lubricants. For evaluating a lubricant, nitralloy blocks, lapped flat to within one light band, are mounted (Fig. 1). Water runs into the bucket at a constant rate, gradually increasing the load on the blocks.

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P. 172ˆ
Determination of the Economic Limit for Non-EOR Projects in Alberta
Authors: Rosenbaum Itzhak
Published: December 2007

This paper provides an easy-to-use procedure by which engineers and corporate planners can determine the economic limit for non-EOR projects in Alberta. The economic limit in this study is defined as the minimum average daily-oil-production rate needed to break even on a before- and/or after-income-tax basis. The economic limit for a single well, for a unit, and/or for a project can be determined by the procedure. The major advantage of this procedure is that it allows reservoir and production engineers to estimate economic limits quickly and accurately without the use of expensive economic models.
The First Oil Well
Authors: Dickey Parke A.
Published: December 2007

The birth of the oil industry on Aug. 27, 1859, was spectacular and its later history has been colorful and romantic.

During the early part of the last century the industrial revolution was in full swing. The demand for oil for lubricating the machinery and illuminating the factories had been supplied from tallow and whale oil. In the 1850's an industry based on the production of illuminating oil from coal was growing rapidly, and a refining technology utilizing thermal cracking and distillation was well developed. It was soon found that petroleum was superior to coal as a raw material, but it was a scientific curiosity, occurring in many places, but in small quantities.

At the same time along the tributaries of the Ohio River a considerable industry had grown up around the manufacture of salt. The brine was obtained from sands at depths up to 1,000 ft. A drilling technology had developed, and the methods of cable tool drilling were mostly invented between 1800 and 1830 along the Kanawha, Muskingum, Conemaugh and Allegheny rivers.

Petroleum was produced along with the brine at nearly all the salt manufacturing plants. At most of these it was used to illuminate the plants and grease the machinery. It was inevitable that this new source of oil should come to the attention of the coal oil refiners, and that attempts should be made to produce oil by drilling. The combination of a large and growing demand for oil, a well-developed refining industry and a highly developed drilling technology provided an explosive mixture.

The spark finally occurred at Titusville, Pa., on the site of a famous oil seep that had been exploited by the Moundbuilders and later by the Seneca Indians and the early settlers. Two New York promoters, George H. Bissell and Jonathan G. Eveleth, formed a company which purchased the farm on which the seeps were located. They were unable to sell stock until they published a glowing report on the commercial value of the oil written by Benjamin Silliman, Jr., a famous chemist and professor at Yale U. Financial support was finally obtained from James M. Townsend, a New Haven banker, and his associates.

Edwin L. Drake went to Titusville in Dec., 1857, to start operations for the company. The first year he opened up the old springs and attempted to exploit them. He decided to drill for oil and employed a salt well driller, W. A. Smith, who came to Titusville in the spring of 1859. Oil was encountered on Aug. 27 at the unexpectedly shallow depth of 69 ft. (Fig. 1). The well produced about 10 B/D. Land along the creek valleys was quickly leased and drillers, teamsters, coopers, speculators and others flocked to the area. The excitement exceeded that of the California gold rush 10 years before.