bluuebunny/crossref_metadata_2025 huggingface dataset:
A Comprehensive Model of Fluid Loss in Hydraulic Fracturing
Authors: Yi Tongchun , Peden J. M.
Published: December 2007

This paper presents a comprehensive model of the fluid-loss process that occurs in hydraulic fracturing. The model treats the three flow regions in the leakoff process—the filter cake, the invaded zone and the reservoir zone—as a composite system with a rigorous account of the interface between the last two zones. This allows automatic consideration of the variation in pressure drops across the three zones and the inclusion of many variable physical aspects in each region. For the description of the filter cake behavior, effects of the internal filter cake, core length, shear rate, and non-Newtonian behavior of fluids have been taken into account. In the invaded zone, the non-Newtonian behavior of the filtrate, the permeability damage caused by the filtrate invasion, and rock and fluid compressibility have been simulated. Different boundary conditions, such as no-flow, constant-pressure, finite, and infinite boundaries, have been incorporated into the model, making it applicable for simulating both laboratory tests and the real leakoff process in fracturing treatments under a variety of conditions.

The model has been validated against laboratory and published data. Excellent agreement between predicted results and test data has been achieved. The analyses show that the non-Newtonian behavior of the filtrate represented by the model has a significant effect on leakoff. Leakoff would be considerably underestimated if a Newtonian fluid filtrate, as in the classic theory, were assumed instead of the non-Newtonian system. We also show that the variation in pressure drops across the three zones may cause a strong nonlinear relation between leakoff and t½ that cannot be explained by the classic theory because constant pressure drops are assumed.
A Multidisciplined Approach to Designing Targets for Horizontal Wells
Authors: Solomon S.T. , Ross K.C. , Burton R.C. , Wellborn J.E.
Published: December 2007

A multidisciplined approach to developing 3D target diagrams and their associated tolerances provides a cost-effective method for designing horizontal wells. The key to this approach is that the diagram quantifies and communicates the uncertainty of the target boundary conditions to others involved in designing and drilling a well. Field examples show how a multidisciplined team creates a 3D target diagram. The preliminary 3D diagram is used to examine the combined uncertainty in the position of the features constraining the target. To maximize the target size, the team must decide on the relative importance of each constraining feature and assign target tolerance limits. The final target diagram minimizes both risk and cost to produce the optimum well design.

Introduction

With horizontal drilling equipment and technology improvements, efforts are now being directed toward optimizing the horizontal drilling process by lowering costs. Planning is widely acknowledged as the key to success in any horizontal drilling project; however, the importance of target design in well planning is not always as well recognized.

Targets for horizontal wells are by necessity 3D. Initially, this concept was a challenge to an industry more familiar with using 2D geometric figures to design vertical or conventional directional well targets. For the first horizontal wells, the simple 2D geometric target shape became a 3D "box." Drilling engineers discovered that these simplistic well targets were inadequate and caused severe problems during drilling be cause they fail to address geological and reservoir uncertainties. Targets were often missed entirely when the formation top of a thin zone "came in" too high or too low. Drilling personnel discovered very quickly how inefficient and expensive it was to "chase" a horizontal target that dipped away. Experiences like these prompted interdisciplinary discussion. Drilling engineers sought to become more informed on the geological aspects of the horizontal prospect. In response, geoscientists found that they needed more information on the horizontal drilling process. It was soon (re)discovered that a well's success was directly related to the amount and quality of information shared among the different people responsible for the drilling project. It was also found that this information and its reliability could be communicated best through pictures by a 3D well target diagram.

This paper discusses the multidisciplined process of designing 3D horizontal well diagrams and provides field examples of their use. The importance of communicating the uncertainty of each target constraint between disciplines is emphasized as the key to cost-effective target design.
Waste Disposal and Earthquakes at the Rocky Mountain Arsenal, Derby, Colorado
Authors: van Poollen H.K. , Hoover D.B.
Published: December 2007

The seismic activity triggered by injection into the RMA well at Derby, and the earthquakes that continued after injection was stopped should serve as a warning to the waste disposal engineer that no underground disposal project is routine. project is routine. Introduction

From 1962 until 1966, waste fluids were injected into the pre-Cambrian formations northwest of Denver, Colo. Since injection started into the 12,000-ft well, earthquakes have been observed in the area. This seismic activity, although different in character, continued when injection was stopped. Consideration has been given to removal of the waste fluids from the well to reduce earthquake magnitude and frequency. This article is a case history of the well, its operation, the observed earthquakes, and a discussion of possible mechanisms. Considerable information is available in various reports. See the references for more detailed information than can be given here.

Drilling and Completion

The Rocky Mountain Arsenal (RMA) disposed of waste waters by various means until 1961, when the deep waste disposal well was completed. Before the well was completed eight geologic formations were considered as possible injection reservoirs: the Hygiene sandstone, the Codell sandstone, the "J" sandstone, the Dakota sandstone, the Morrison formation, the Lyons formation and the Fountain formation. The hole was to be drilled to a total depth to penetrate the pre-Cambrian rocks. pre-Cambrian rocks. During drilling it was found that the potential reservoirs were tightly cemented with silica and that Cambrian was then considered as a disposal prospect. Waste disposal through wells is practiced in many states. The RMA disposal well is unique in that it is by far the deepest (12,000 ft) and in that the reservoir consists of fractures in crystalline rock as opposed to sedimentary rocks in other projects. Operating conditions of the well fall within the range of all wells. The maximum wellhead injection pressure for the RMA well was 1,100 psi during an injection rate of 300 gal/min. The greatest depth of other waste disposal wells is 7,650 ft; the maximum wellhead pressure is 400 psi, and the maximum injection rate is 700 gal/ min. During the drilling of the well, lost circulation was observed in the Lyons formation (9,582 to 9,772 ft). Eight instances of mud losses were noted. These ranged from a 10- to a 320-bbl loss. Cores indicated the formation to be fractured. The Fountain formation (9,772 to 11,880 ft) appeared to be highly fractured to a depth of 10,400 ft, with some fracturing at greater depths. Lost circulation was frequently experienced while drilling through the Fountain, mostly between 9,960 and 10,250 ft. The lowest mud loss took place at 11,080 and was the most serious one in the well, with some 1,350 bbl lost. The well was cased to 11,171 ft and subsequent drilling did not encounter lost circulation until after a core was cut in the pre-Cambrian (11,950 ft total depth).

P. 983
Simplified Gravity-Drainage Oil-Production Model for Mature Steamfloods
Authors: Closmann P. J.
Published: December 2007

A model has been formulated for estimating the oil production during the mature phase of a steam-injection process. This model assumes that complete steam overlay has occurred and that subsequent gravity drainage of oil is accelerated because of the viscosity reduction in the heated-oil phase. The predicted oil-production rate declines approximately linearly at early times, depending on the initial oil level in the reservoir and at a gradually decreasing rate toward zero at long times. The model shows good agreement with various field cases.
Laboratory and Numerical Discontinuum Modeling of Wellbore Stability
Authors: Rawlings C.G. , Barton N.R. , Bandis S.C. , Addis M.A. , Gutierrez M.S.
Published: December 2007

Wellbore-stability analyses based on intact wellbore walls can be too conservative because failed/fractured zones around wellbores relieve stress and give support. Wellbore-breakout analyses indicate that most drilled wells experience deformation beyond the rupture stage and that this deformation is acceptable for the drilling process. Validation of the methods available to predict wellbore stability requires a comparison of theoretical models with experimental simulations of wellbore behavior. This paper describes a series of scaled laboratory wellbore-stability experiments carried out under various borehole inclinations and stress conditions. The goal was to investigate the influence of the fractured zone, stress anisotropy, well deviation, and well orientation on wellbore stability. Classic log spiral fracture geometries were obtained around the wellbore, and the effect of the fractured zone on wellbore stability was studied with a distinct-element program called the universal distinct-element code (UDEC). Results show the importance of taking into account the stability of the fractured zone and subsequent wellbore breakout when wellbore stability is considered.

Introduction

Wellbore stability requires a proper balance between the uncontrollable factors of earth stresses, rock strength, and pore pressure and the controllable factors of wellbore fluid pressure and mud chemical composition. The causes of instability can be classified as either chemical or mechanical effects (this paper considers only mechanical effects). Recent research into wellbore stability concentrated on assessing the problem from a continuous-media concept. This paper, however, also assesses the stability of the fractured "breakout" zone around wellbores with UDEC.

The increasing use of deviated, extended-reach, and horizontal wells has escalated the demand for wellbore-stability studies during the planning stages of oil and gas fields. Continuum analytical and numerical models used to predict wellbore stability generally consider the stresses developed in a plane perpendicular to the wellbore axis and how these stresses compare with the strength of the surrounding material (obtained from triaxial tests).
Successful Control of Fracture Height Growth by Placement of Artificial Barrier
Authors: Mukherjee Hemanta , Paoli B. F. , McDonald Todd , Cartaya Hugo , Anderson J. A.
Published: December 2007

This paper presents a method to control fracture height growth through the selective placement of artificial barriers above and below the pay zone. These barriers are created prior to the actual treatment by pumping a mix of different size and density proppants with low viscosity carrying fluid, that allows fast settling of these proppants or, if desired, floatation to the top of the fracture channel or both. Typically a viscous pad is pumped to create a fracture channel. This pad is followed with 5–10 cp fluid slurry carrying a mix of heavier proppant that settles to the bottom of the fracture channel and a light proppant that rises to the top of the fracture channel. The proppant slurry is allowed to bridge at the top or the bottom tip of the fracture, inhibiting further growth of these tips. The actual treatment following this barrier placement is thus focused through these barriers confining itself within the barriers and resulting in a longer extension within the pay zone. Such controlled fracture height allows further optimization of fracture length by reducing or increasing the amount of proppant as called for in the design. Two case studies are presented in this paper from two formations known to suffer from fracture height growth.
Low-Permeability Gas Well Performance At Constant Pressure
Authors: Stewart Paul R.
Published: December 2007

Presented here is an analysis of the long-term production performance of some low-permeability wells in the Big Piney-LaBarge Frontier gas field of Wyoming. A rigorous technique is proposed for predicting the abandonment pressure, and thus the recovery efficiency, of such gas wells.

Introduction

The petroleum industry's search for new natural gas reserves has progressively led to the development of reservoirs that have been assumed to be too tight to provide a reasonable return on invested capital. The Frontier reservoir in the Big Piney-LaBarge field of Wyoming is an excellent example of a lower-permeability field that, through the use of sophisticated sand-fracturing techniques, is now a profitable operation, with initial recoverable reserves in excess of 3 Tcf.

The Big Piney-LaBarge Frontier gas field is located along the western margin of the Green River Basin in western Wyoming. It is approximately 25 miles long, has a maximum width of 16 miles, and is located on the LaBarge platform, which is basically a large anticlinal structure overridden by thrust faulting from the west. It is the largest gas field in Wyoming, in both size and production rate, currently producing approximately 160 MMcf/D from about 220 wells. Cumulative production to date is more than 550 Bcf. Overall spacing is essentially 320 acres/well, with recent infill drilling programs on 160 acres in selected areas.

The Frontier formation, of Cretaceous age, has been separated into the First, Second, and Third Frontier zones. The average gross interval covered by these zones is 650 ft, with approximately 130 ft of gross sand and 35 t of net sand. All productive zones are commonly combined and produced as one "reservoir".

The zones are very widespread but they are very heterogeneous both laterally and vertically, and vary from fine- to medium-grained, well sorted to conglomeritic, with variable amounts of silt and clay matrix. Eastward, the sands become progressively more silty and tighter. Porosities are rather uniform, but permeabilities are extremely variable, and generally quite low. Over-all average rock and gas properties are as follows:Effective porosity 16 percentWater saturation 40 percentPermeability (absolute) 1 mdPermeability (to gas) 0.5 mdAverage perforated depth 7,050 ft (+ 150 ft)Bottom-hole temperature 165°FCondensate content 5 bbl/MMcf
Prediction of Deposition of Calcium Sulfate Scale Under Down-Hole Conditions
Authors: Vetter O.J.G. , Phillips R.C.
Published: December 2007

The thermodynamic method of calculating calcium sulfate scale has been improved by including the effects of complicated down-hole phase equilibria. Although the modified method has its limitations, it appears to provide more reliable results.

Introduction

Calcium sulfate (CaSO4) scale, especially gypsum, still causes unpredictable problems in many oil fields. This type of scale can cause severe plugging of equipment and producing formations; it creates the necessity of costly workovers and stimulation jobs. The best method for combating this scale seems to be the application of inhibitors - for example, by squeeze techniques - before the scale is formed. The reason is obvious: it is much more economical to prevent the formation of scale than to repair the damage caused by it. To apply the most suitable inhibition method, we have to know if and to what extent scaling occurs. At least some knowledge about the likely location of scale within the wall is equally important. The present methods of predicting scale in an oil field do not give all the answers, even though the literature contains enough data to develop and prove a more precise and reliable method.

It is still common practice to wait for a production decline in the field, then pull the tubing and find - more or less accidentally - scale on the now-exposed metal surface. This scale sample is considered a proof for the occurrence of scale. This procedure can be very costly, and irreparable damage can be done before the scale is detected. Besides, this method fails frequently because scaling can occur even without the deposition of scale in the tubing.

A better method for scale prediction is the use of water analyses and solubility data of CaSO4 compounds in the oilfield brines. There are many publications1–9,12,13,15,16 on the solubility of calcium sulfate compounds in water and brines at 1 atm. Most of the data in these publications are in good agreement. Together with the information from the water analyses, they are used to predict potential scale deposition. Diagrams, empirical equations, or thermodynamic relations are used to find the "maximum" solubility of calcium sulfate, mostly gypsum, in a water of similar composition.6–9,12–14 If the Ca++ and SO4-- concentrations in the actual water approximate the calculated "maximum" concentration of CaSO4, the field brine is said to have a "scaling tendency". We believe that this method can give only vague and unreliable information because it gives the solubility of CaSO4 or its hydrates at 1 atm only.
Digital-Log Management System
Authors: Tan A. A. , Potts J. K.
Published: December 2007

Digital-log data is essential to any petrophysical and log-correlation software package. Gathering of such data, however, is often painstaking and laborious. A significant portion of the interpreter's valuable time is spent in data compilation and verification. In response to this data management need in Conoco, the digital-log management system (called LMS) was developed.

The LMS uses existing data-storage standards and stable technology to implement a common digital-log management solution throughout the company. To achieve system portability, LMS is delivered with a stable well-data model and a comprehensive log catalogue maintained in a relational database.
1993 U.S. Petroleum Engineering Manpower Supply and Demand
Authors: Wattenbarger R.A. , Morriss Steven
Published: December 2007

The SPE Manpower Committee's U.S. surveys show that large companies will decrease their hiring while small companies and service companies will increase their hiring of engineers. During 1992–93, only about 65% of graduating petroleum engineering students were known to have jobs. Another finding is that, overall, new U.S. SPE membership is decreasing, while non-U.S. membership is increasing.

Introduction

Each year, the SPE Manpower Committee reports on the results of petroleum engineering manpower supply and demand surveys to inform SPE members about hiring patterns of engineers in the petroleum industry and the supply of graduates from U.S. petroleum engineering schools.

The 1993 demand survey was sent to selected employers of petroleum engineering graduates, including large and small producing companies and service companies. Only 19 companies responded with usable surveys, compared with 26 usable surveys returned last year (see Table 1). Companies were asked to report on four items: total engineering graduates employed at year-end, petroleum engineering graduates employed at year-end, total engineering graduates hired on campus, and petroleum engineering graduates hired on campus.

For each item, companies reported an actual figure for 1992 and forecasted values for 1993–95. Forecasted figures included estimates for high, low, and most likely scenarios for 1994–95. Table 1 compares this year's demand survey response with last year's response.

The 1992–93 supply survey was sent to all petroleum engineering schools in the U.S., including those offering petroleum engineering options within other degree programs. Like last year, 20 schools responded to the survey. This response represents about 90% of the petroleum engineering enrollment in the U.S.

For the 1992–93 (actual) and 1993–94 and 1994–95 (forecast) academic years, each school reported (1) BS-, MS-, and PhD-degree graduates, total and those seeking employment, and (2) employment of 1992–93 graduates by type of employer. It was assumed that the 1992–93 academic year graduates would be hired in the 1993 calendar year, and so on. Students not seeking employment included international students returning home and students entering graduate school or the military.

Demand Survey

Producing companies responding to the demand survey were divided into large-company and small-company groups on the basis of their engineering employment. Companies employing 150 or more engineers were considered large companies. This group corresponds to the top 13 oil and gas producers on the basis of equivalent U.S. daily oil production. The "top 13" group accounts for about 84% of U.S. production. Seven usable responses were obtained from this group, representing a total engineering employment of 4,007 at year-end 1993.
A Critical Evaluation of Short and Long Range Correlation Methods for Heterogeneous Rocks
Authors: Du Changan , Ershaghi Iraj
Published: December 2007

Indications of short and long range correlation are important basis for stochastic modeling of geological reservoirs. This paper examines the merits of various statistical methods for recognizing rock properties correlations in vertical columns. Specifically the persistence of patterns analyzed by the R/S method were analyzed with the application of semi-variogram and power spectral density methods. From synthetically generated patterns (fGn, fBm), short and long range correlations for large data sets corresponding to pure, layered and composite homogeneous and heterogeneous sets was analyzed. Additionally, the impact of the overlap averaging on the estimation of correlation were evaluated. Concurrent analysis using the three techniques is shown to enhance the interpretation of the correlation type.
Discrimination Between Reservoir Models in Well-Test Analysis
Authors: Anraku Toshiyuki , Home R. N.
Published: December 2007

In well-test analysis with nonlinear regression, discrimination between candidate reservoir models is a key procedure. Graphical analysis now performs this step, with the pressure derivative plot and confidence intervals used to select an adequate model. Human bias may influence the selection by graphical analysis, however, and the result may vary according to the interpreters. Confidence intervals can give a quantitative evaluation of model discrimination, but it sometimes provides inappropriate results.

We propose a new quantitative method, the sequential predictive probability method, to discriminate between candidate reservoir models. This method is based on Bayesian inference, in which all information about the reservoir model and, subsequently, the reservoir parameters deduced from well-test data, is expressed in terms of probability and is regarded as a direct extension of the idea of confidence intervals. This method gives a unified measure of model discrimination. We demonstrate the applications of this method to synthetic and actual field well-test data.
Pull-Through Forces in Buckled Tubing
Authors: Mitchell R. F.
Published: December 2007

Conventional analysis of tool passage through buckled tubing is based on planar curvature assumptions. However, helical buckling involves three-dimensional geometry which can be further complicated by wellbore curvature. This paper is an analysis of tool clearances within tubing, including the effects of tool orientation, helical buckling and wellbore curvature. The maximum free passage tool length for combined buckling and wellbore curvature is determined. Alternately, the minimum pull-through force for a given tool length is determined.
A New Method of Overbalanced Perforating and Surging of Resin for Sand Control
Authors: Dees John M. , Handren Patrick J.
Published: December 2007

Gravel packing of perforations is the conventional method for sand control in the petroleum industry. Case histories of 12 well treatments provide details of a new procedure for high-energy resin placement that controls sand in a formation. The new consolidation method uses an extremely overbalanced pressure surge with liquid resin on perforations. This paper presents the problem, theory, process description, job procedure, and results of resin treatments with perforating or surging with a high-energy overbalanced pressure pulse. Highlights include potential applications. Benefits of the technique include accelerating on-line production and reducing completion rig time spent on controlling sand. The method appears to yield equal or better results than previous conventional gravel-packing techniques.

Introduction

The underbalanced method is the petroleum industry standard for perforating wells requiring sand control. Efforts to prevent the perforating guns from sanding up with for mation sand restrict the amount of underbalanced differential pressure. Sufficient underbalanced pressures for full perforation cleanup is not standard. Perforations that are not cleaned adequately will not readily accept resin during matrix injection.

Operating companies took underbalanced perforating to offshore operations with the introduction of tubing-conveyed perforating guns in 1970. Today, few offshore operators consider overbalanced pressure in wellbores when perforating a well for sand control. Environmental concerns or equipment limitations provide a few cases of overbalanced perforating. In these rare instances, the fluid hydrostatic pressure will slightly exceed reservoir pressure. This reduces fluid invasion from mud or expensive brine water before the gravel-pack procedure.

Until now, the industry has accepted underbalanced perforating and gravel packing as the best way to complete a well for sand control. Oryx Energy Co. began a research project on sand control in wells with gas generators and resin in Oct. 1988. Success with the propellant-gas fracture resin placement method led to extension of the research to include extreme overbalanced perforating with resin in Aug. 1990. The downhole high-energy placement of resin for sand control now challenges the industry's conventional standard of underbalanced perforating and gravel packing for sand control.
Development of a Surface-Controlled Electric Gas-Lift Valve
Authors: Schnatzmeyer M.A. , Yonker J.H. , Pool C.M. , Goiffon J.J.
Published: December 2007

In the design of conventional gas-lift installations, the size and setting of the operating valve are determined according to theoretical performance at nominal well conditions. Unfortunately, gas-lift valves are subjected to the effects of a dynamic and often transient environment that can significantly com promise operating efficiency.

To manage these environmental effects better, a new electric gas-lift valve (EGLV) system in which the size of the downhole gas injection orifice can be remotely adjusted from a surface control unit has been prototyped and field tested. The EGLV system consists of an electrically operated, surface-controlled downhole valve, a downhole pressure transducer, tubing mandrel, electric cable system, and surface controller. By combining known well parameters with real-time tubing pressure and valve-position data relayed from downhole, the control unit can adjust the valve to current well conditions. This capability allows the operator to produce the well with maximum effectiveness for whatever production priorities have been chosen.

Controlling valve response in this manner can be especially desirable for such applications as limited lift-gas availability, limited compressor capabilities, drawdown within designated limits, control of short-term production upsets, and areas where reservoir management objectives are specific to the application.

Enhanced efficiency of gas-lift operation and optimized production were the goals of this developmental program, and testing results obtained to date have shown enough promise to initiate the next stage of the program-an advanced wireline-retrievable version of the system.

Introduction

The use of gas lift for primary recovery is common. Operational theory and equipment design have continued to improve over the years, but the transient nature of the gas-lift environment and numerous interrelated parameters have made the goal of optimized gas-lift performance a moving target. One of the most recently developed techniques is valve performance testing. The valve is tested for its response to a range of particular well and gas-injection conditions. Although this procedure can result in a better installation design and a better under standing of well conditions, valve orifice size and opening sensitivity are still fixed parameters; they are preset at the surface to a defined set of nominal well conditions. Wells that produce steadily and change slowly over time have the best chance of being produced efficiently on conventional gas-lift equipment. Even in those cases, however, the actual operating parameters can differ significantly from calculated nominal figures.
Combination Fracturing/Gravel-Packing Completion Technique on the Amberjack, Mississippi Canyon 109 Field
Authors: Hannah R. R. , Park E. I. , Porter D. A. , Black J. W.
Published: December 2007

This paper describes a one-step fracturing/gravel-pack (frac-and-pack) completion procedure conducted on the BP Exploration Amberjack platform beginning in early 1992. This platform is 35 miles southwest of Venice, LA. The first four completions on this platform had an average positive skin values of 21. The goal of the frac-and-pack procedure was to reduce these skins to nearly zero. In total, 24 frac-and-pack operations were performed. Details of the fracture design, prefracture testing, fracture design and execution, and production response and a continuing optimization program are discussed. The fractures were performed with the screens in place with the gravel pack after the fracturing operation. The treatments were designed for the tip screenout technique1,2 to create wide fractures and to provide proppant loadings exceeding 8 lbm/ft2.

This paper presents the trend of the declining skin values, along with a discussion of time-dependent skins. The changes in fluids, breakers, and proppants are also presented. The average skin on 14 frac-and-pack completions was 5.3. The average skin on the final eight completions was 0.2.
The Philosophy Behind Trading Oil Properties
Authors: Hulsey Bob T.H.
Published: December 2007

Introduction

Since 1955, The Chase Manhattan Bank has headed financing of over $1 billion for oil and gas property acquisitions. Of these transactions, 25 have been analyzed in detail and the results of the study are shown in Fig. 1. Factors often associated by appraisers with values are shown. Bar graphs show the ranges for the composite group, and averages were obtained by adding individual values and then dividing by 25. As discussed by Terry and Hill in 1953, rate of return is the over-all rate after taxes. These data are presented here merely to indicate the wide ranges which occur in relation to the averages. It is not proposed to discuss or comment on the validity of using this information. Furthermore, since the literature is replete with methods of evaluation explained in detail, no new approach will be suggested. Rather, the purpose of this paper is to note some of the forces affecting the market for petroleum producing properties and some of the pitfalls which may be encountered on the road to a purchase.

Market for Properties

Stocks are traded at the New York Stock Exchange, but there is no such establishment where oil and gas properties can be bought and sold. Yet a market exists for such properties. Potential buyers and sellers constitute this market, and markets exist for each type of property interest. For example, nontaxable institutions and funds are predominant purchasers of choice producing royalties. Market knowledge is as vital to an able appraiser or a successful buyer or seller as is information on prior sales.

Market Forces

Petroleum is the leading source of energy in the United States and the Free World, and the competition to supply this energy is fierce. The resulting instability of refining and marketing earnings has created a great demand for producing properties. At the same time, there has been a growing trend toward liquidation by many producers. However, demand continues to exceed supply, creating a "sellers market" this is the dominant force in the producing-property market today. Other factors include economic conditions, political stability, proration, import regulations, discovery success, availability of capital and financing, and the quality of available properties.

Pitfalls

The more common causes of unsuccessful attempts to purchase producing properties may he traced to smugness and or laziness on the part of the appraiser. A firm belief in the accuracy of a first computation often dooms a transaction. Computations are the tools of an evaluator they are not the final answer. Only judgment and common sense can yield a proper result. How many assumptions or approximations are made in an engineering appraisal? Usually several hundred. Fig. 2 schematically represents such a calculation.

JPT

P. 727^
Completion and Production Results From Alternate-Path Gravel-Packed Wells
Authors: Bryant D. W. , Jones L. G.
Published: December 2007

A successful gravel pack requires two things: perforations packed with gravel-pack sand and a completely packed annulus. Failure to obtain either one can result in low productivity and/or a sand-producing gravel pack. Alternate-path gravel packing ensures that the annulus will be completely packed and that all perforations taking fluid will be packed with gravel-pack sand. Alternate-path gravel packing has provided long and highly productive completions without any sand production.

This paper presents completion data and production results from 39 wells completed with the alternate-path gravel-pack technique. The completion data include completion length, net perforations, carrier fluid, sand placement outside casing, workover fluid, and return rate during packing. Production results include qualitative discussion of all completions with quantitative results, including permeability-thickness product and skin on select completions.
Ultrasonic Removal of Near-Wellbore Damage Caused by Fines and Mud Solids
Authors: Venkitaraman Adinathan , Roberts Peter M. , Sharma Mukul M.
Published: December 2007

Laboratory experiments were conducted to investigate the feasibility of using ultrasonic energy to reduce formation damage caused by fines and mud solids. Cores were damaged with drilling muds in a dynamic filtration cell. Damage caused by fines migration was simulated with freshwater injection. The damaged cores were then treated with ultrasonic energy at various frequencies and intensities. The experiments were conducted with fully brine-saturated cores and cores partially saturated with decane. Permeability was monitored as a function of ultrasonic treatment time during backflow for three different sections of each core. Permeability increase, the depth of treatment, and the ultrasonic energy requirements were investigated for both sandstone and limestone cores. The results showed that permeability increased by a factor of three to seven after ultrasonic treatment for cores that were damaged by mud solids and fines migration. Treatment was successful for frequencies of approximately 20 to 80 kHz and acoustic intensities of approximately 20 to 250 W/m2. For these wavefield parameters, the effective depth of treatment for reducing fines damage was approximately 2.5 in. Damage caused by mud infiltration penetrated only the first 2.5 in. of the cores, and thus, ultrasonic treatment had no effect on deeper sections.
The Effect of Wormholing on the Fluid-Loss Coefficient in Acid Fracturing
Authors: Hill A. D. , Zhu Ding , Wang Yimei
Published: December 2007

In most acid fracture designs, a leakoff model developed for proppant fracturing is used to calculate the acid volume lost into the formation. Because wormholing in acid fracturing results in a few large channels near the fracture, the leakoff velocity of the fracturing fluid can be higher in acid fracturing than in proppant fracturing. This paper presents a new leakoff model that includes the effect of wormholing on the overall fluid-loss coefficient. The leakoff model is based on a volumetric model describing wormhole growth in acid fracturing. Conveniently, the leakoff velocity based on the volumetric model for wormholing is still inversely proportional to the square root of treatment time. Laboratory coreflood results are presented that support the use of the volumetric model for the linear flow region near the fracture walls.

The results of the model show that the overall fluid-loss coefficient depends strongly on the number of PV required for wormhole breakthrough in a coreflood. A large number of PV to breakthrough means a slow wormhole growth rate, which occurs more commonly in dolomite compared with limestone. The effect of wormholing on the overall fluid-loss coefficient is insignificant in acid fracturing of dolomite. However, for limestone, the number of PV to breakthrough is small and wormholing increases the fluid-loss coefficient significantly, especially for a gas well. An example in the paper shows that the overall fluid-loss coefficient can be more than 100% higher because of wormholing in a typical case for a gas well in a limestone formation.
Integration of Production Analyst and Microsoft Excel's Solver for Production Forecasts and Optimization
Authors: Arnondin M. C.
Published: December 2007

Mobil North Sea Ltd. has used OGCI's Production Analyst (PA) for several years for reservoir management and surveillance. Once most professionals had been migrated to Microsoft Windows and Excel, we began to integrate the spreadsheet with PA for specialized applications. Production optimization and forecasts are two applications of significant economic benefit.

We developed an Excel spreadsheet and macro that use the Solver and production-decline data from PA for predicting the maximum platform oil production while honoring gas-compression and waterhandling constraints. By use of PA, a database of decline-curve information is generated by well for the relationships of oil rate, GOR, and water cut to cumulative oil. Other input required for the forecast are the combination of months and years to forecast, gas compression limit, water-handling limit, and platform efficiency at each timestep.

This model adds value to our operations by leveraging existing products and data to predict facility-constrained production schedules. A custom program with this type of functionality would certainly be more expensive than the combined costs of PA and Excel. The integration of these tools provides cost-effective solutions to the specialized problems experienced in oil and gas exploitation.
Prediction of Cloud Point Temperatures and Amount of Wax Precipitation
Authors: Pedersen Karen Schou
Published: December 2007

The paper presents a vapor-liquid-solid model for predicting phase equilibria of oil mixtures taking into account the possible formation of a wax phase. The gas and liquid phases are described using the Soave-Redlich-Kwong equation of state while the wax phase is assumed to be an ideal mixture. Only part of the heavy hydrocarbons are considered to be able to potentially enter into a wax phase. A procedure is developed for estimating the fraction of the heavy hydrocarbons which may potentially form wax. Calculation results agree very well with experimental wax precipitation data.
An Investigation Into the Application of Fuzzy Logic to Well Stimulation Treatment Design
Authors: Xiong Hongjie , Holditch S. A.
Published: December 2007

Designing an optimal stimulation treatment for an oil or gas well is a complex procedure requiring in-depth knowledge and experience. This paper describes how fuzzy logic applies to stimulation design and clearly illustrates how to apply fuzzy logic theory. The paper also discusses the advantages and disadvantages of applying fuzzy logic to well stimulation design.

Fuzzy logic evaluators can be applied to study, evaluate, and determine the best methods to improve productivity in oil and gas wells or injectivity in water wells. The approach can be extended to the solution of other problems associated with drilling, completing, and working over wells and with formation damage diagnosis.
Polymer Flood of the Rapdan Pool
Authors: Pitts Malcolm J. , Campbell Tom A. , Surkalo Harry , Wyatt Kon
Published: December 2007

A polymer-flood pilot project in the Rapdan field is documented from laboratory design and numerical simulation to production performance and projected economics. The Rapdan field produces 10-mPa · s oil from the Upper Shaunavon sand at a reservoir temperature of 55 °C. Average permeability is 0.114 μm2, average porosity is 18%, and Dykstra-Parsons coefficient is 0.8. The field was discovered in 1953, and waterflood began in 1962. In Jan. 1986, a polymer pilot was initiated in a portion of the field with a PV of 456 × 104 m3. The pilot consists of 13 producers and 5 injectors drilled on 162 × 103-m2 spacing. By Dec. 1994, 43% PV of a 21-mPa · s polymer solution had been injected into a confined, central five spot (Wells 12-12 and 12-12A). The oil cut increased from a stable value of 8% during the waterflood to a peak value of 25%. The corresponding daily oil production increased from 8 to 28 m3/d. The performance of the total project oil production increased from 65 m3/d at an oil cut of 18% to a peak production of 180 m3/d at an oil cut of 36%. Production rate has declined from 140 m3/d in 1991 to 106 m3/d in Dec. 1994, with a corresponding oil-cut decline from 25% to 20%.
Improved EOR by Use of Chemicals in Combination
Authors: Baviére Marc , Glénat Philippe , Plazanet Véronique , Labrid Jean
Published: December 2007

Present crude oil prices are too low for the economic implementation of chemical EOR processes based on surfactants and polymers. However, considering recent progress made in use of surfactants, polymers, and alkalis in a synergistic way, it appears that significant improvements can be made in the efficiency/cost ratio of the process, which could make it attractive within a more favorable oil-price context. To illustrate this, the method used in developing the process is applied to a field case characterized by some properties not really suitable for chemical processes (i.e., a high clay content that magnifies ion exchange and related permeability effects, a pore-diameter distribution that prevents complete tertiary oil recovery, and an acid number that is not high enough to give substantial oil production when alkalis alone are used). Nevertheless, relatively reasonable performances have been obtained by combining the different chemicals.

In the first series of oil-recovery tests, the process was implemented conventionally with the aim of taking advantage of ion-exchange mechanisms. With an optimal micellar system, tertiary oil recovery did not exceed 50% original oil in place (OOIP). In a second series of tests, calcium ions contained in the connate water and those fixed on the clays were first removed by an alkaline solution. Then surfactants and polymer were injected, both with the same alkali. In this way, oil production was boosted to 70% OOIP, while the efficiency/cost ratio was improved by a factor of 3. These performances were ascribed to low interfacial tensions (IFT's), appropriate mobility control, and a drastic reduction of surfactant and polymer retention. From these results, the alkali-surfactant-polymer process could be expected to be used in a wide range of field conditions and, in particular, with crude oils that do not necessarily have a high acid number.
Two-Phase Flow Splitting at an Impacting Tee
Authors: Hong K. C. , Griston Suzanne
Published: December 2007

This paper describes laboratory air/water and field steam flow tests conducted to develop a reliable method for predicting the qualities of split streams and to find tee insert devices that increase the range of vapor-phase split ratios for which split qualities are equal. The results show that an empirical correlation based on air/water tests can be applied to field steam-distribution systems for predicting phase-splitting problems. The splitting problems are corrected by using the tee insert devices tested. Test data show that of the insert devices that were evaluated, the downstream nozzles produced equal-quality splits over the widest range of vapor-phase split ratios.
Analytical Upscaling of Permeability for 3D Gridblocks
Authors: Lee Jaedong , Kasap Ekrem , Kelkar Mohan G.
Published: December 2007

With modern conditional simulation methods, detailed reservoir descriptions can be constructed on a very small scale. Many methods also allow detailed descriptions which include basic geologic features such as cross beds and laminations. Unfortunately, present flow simulators are not capable of incorporating these small scale descriptions due to computational limitations. The small scale values, especially, the permeabilities, need to be upscaled appropriately to the size suitable for flow simulations.

Many methods, some numerical and some analytical, have been reported in the literature to upscale the permeability values. Numerical methods are computationally expensive, whereas, many analytical methods are restricted to two dimensions. This paper presents an analytical method to estimate the upscaled permeability tensor in three dimensions using small scale permeability values. The method is based on dividing the upscaled block into eight smaller blocks and using cross flow and non-cross flow averaged permeabilities based on Darcy's law. The method is validated by comparing the results from a numerical simulator.
Maintenance Improvements on Offshore Fuel Oil Terminals
Authors: Salo Eric A.
Published: December 2007

Two marine terminals for receiving heavy fuel oil for power plants of the Pacific Gas and Electric Co. have power plants of the Pacific Gas and Electric Co. have been in service at Monterey Bay and Estero Bay for many years. The moorings were designed for the T-2 class tankship. The layout of the Estero Bay terminal, which serves the Morro Bay power plant, is shown on Fig. 8. The Monterey Bay terminal serves the Moss Landing power plant, which is essentially a duplicate. For many years the maintenance program for each terminal involved an annual overhaul during which the mooring buoys and active mooring chain would be lifted aboard a derrick barge for cleaning, painting and replacement of worn chain and shackle pins. The submarine oil delivery hose would be inspected by a diver and sections would be interchanged to distribute wear. Any indication of damage would call for disassembly of the string of eight 24-ft lengths of hose and inspection on the deck of the barge. A vacuum test with plexiglass seal plates at each end is used to check for separation of the hose liner. On reassembly the hose and the pipeline to the plant are subjected to hydrostatic test. At this time the cathodic protection potential at the seaward end is checked also. potential at the seaward end is checked also. Over the years it was learned that the wear of the active dip section of the mooring chain resulted in 40- to 50-percent loss of chain section between overhauls. This substantial loss of strength was due principally to wave action and was more or less constant principally to wave action and was more or less constant regardless of the number of cargoes delivered. Because of the considerable cost of overhaul and the disturbing loss of chain strength a study was made of means of reducing the critical wear of the chain links. Analysis of the wear indicated that abrasive action of bottom sand stirred up by the incessant working of the dip section under the rise and fall of the buoys was a major factor.

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