bluuebunny/crossref_metadata_2025 huggingface dataset:
Two Errors in Pressure Measurement Using Subsurface Gauges
Authors: Ainsworth W.J. , Hawkins Murray F.
Published: December 2007

Introduction

In all types of subsurface pressure gauges the extension which occurs in the pressure-sensitive element is a function of the difference between the external (well or calibration) pressure and the internal pressure within the gauge, rather than a function of the external pressure only. The internal pressure is near atmospheric and depends uponthe quantity of air sealed within the gauge at the time of calibration or measurement,the quantity of moisture (liquid water), if any, sealed within the gauge, andthe temperature at which the calibration or well measurement is made.

Part of this correction for the change of internal pressure with temperature is taken care of by the customary temperature coefficient of the gauge. However, part of it is not, and while this portion may be only a few psi, it is nevertheless predictable or preventaple, and should be considered in precision measurements.

In precision measurements the error introduced by sealing the gauge during a well test at a different temperature and pressure from that of calibration may be corrected for by using the equation presented, or it may be prevented by taking care always to seal the gauge at near calibration conditions. The error introduced by sealing moisture in the gauge may be prevented by taking care to keep moisture out of the gauge, or by removing the moisture by either warming or evacuating the gauge. Both of these errors are independent of the range of pressure measurement and the type of gauge, and are in addition to the usual temperature correction.
Using Parameter Estimation Techniques To Convert Centrifuge Data Into a Capillary-Pressure Curve
Authors: Bentsen R.G. , Anli J.
Published: December 2007

Previously reported techniques for converting basic centrifuge data into a capillary-pressure curve have one serious drawback: they all involve the graphical or numerical differentiation of experimental data. The problems associated with the differentiation of experimental data can be avoided by using the parameter estimation techniques proposed here. The parameter estimation techniques proposed here. The purpose of this paper is to demonstrate The advantages purpose of this paper is to demonstrate The advantages of using parameter estimation techniques for obtaining a capillary-pressure curve from centrifuge data.

Two parameter estimation methods for handling centrifuge data were investigated and compared with a modified form of Hassler's technique for interpreting such data. This investigation indicates that, while Hassler's method and the parameter estimation techniques were equally able parameter estimation techniques were equally able to generate the capillary-pressure curve from centrifuge data, the latter procedures are preferable since they use various integration preferable since they use various integration schemes and, hence, avoid the differentiation problems associated with previously reported problems associated with previously reported methods of data interpretation. Moreover, if the parameter estimation techniques are used, the data can be smoothed and the irreducible water saturation, displacement pressure, and capillary-pressure normalizing parameter can be estimated.

Introduction

The theory for converting experimental data obtained with a centrifuge into a capillary-pressure curve was developed by Hassler and Brunner. The basic equation used in the conversion is

P2 a ci Sn(x) dxP S = cos ---- .....(1)ci n 2 × 21 - ----- sin aPci

wherep 2P = ----- w (re2 − ri2), ci 2

p 2x = ------ w (re2 − r2), 2

and

ricos a = ----- .re

Hassler and Branner were unable to find an analytical solution to Eq. 1, but they demonstrated bow it could be solved by the method of successive approximations. Since this method is very tedious in application, Hassler and Brunner preferred using a simplifying assumption that amounts to setting ri equal to re. This assumption, which the authors considered to be reasonable provided the ratio ri/re was greater than 0.7, resulted in the equation

P ciPci Sn = Sn(x)dx,

0

from which it follows that

d Sn (Pci) = ------ (Pci Sn)................(2)dP

Setting ri equal to re assumes that the length of the core is negligible compared with the radius of rotation of the core. Hoffman has shown that this assumption is unnecessary, and that Eq. 3 should be used to solve for the saturation at each speed level.

2 cos adSnS (P) = -------- (S + P ------)....(3)n ci 1+cos a n ci dPci

Eqs. 2 and 3 can be solved by taking slopes of graphs of Sn and Pci Sn vs Pci.

SPEJ

P. 57
Consistency Check and Reconciliation of PVT Data From Samples Obtained With Formation Testers Using EOS Models
Authors: Kikani Jitendra , Ratulowski John
Published: December 2007

Accurate description of hydrocarbon fluids is critical to field development planning including facilities design, recovery efficiencies, secondary recovery processes, and remedial procedures for intervention. Despite this large impact of fluid characteristics on field development, generally a small number of downhole fluid samples are collected. Often they are not representative of the reservoir fluid for a variety of reasons. These include phase separation caused by drawdown during sampling and leakage during recovery and transport.

In this paper we show the utility of a routinely reported piece of data, namely, the tool opening pressure, in a quantitative manner to check the quality of the sampled fluid. The condition of the fluid is modeled by performing an isochoric flash experiment that mimics the actual conditions. A significant discrepancy in modeled and real opening pressure data often suggests leakage. When this method is used, the fluid samples may be approximately reconstructed, multiple fluid samples from the same reservoir may be reconciled, and a consistent phase behavior of the fluid may be determined.
Sulfide Removal and Prevention in Gas Wells
Authors: Hitzman D. O. , Dennis D. M.
Published: December 2007

Major problems in oil and gas operations result from the biogenic formation of H2S in the reservoir. The presence of H2S results in increased corrosion, iron sulfide formation, higher operating costs, reduced revenue, and constitutes a serious environmental and health hazard. A new technology that removes and prevents the formation of biogenic H2S has been developed. The technology is based on the addition of low concentrations of a water-soluble nutrient solution, which selectively stimulates the growth of an indigenous microbial population, thereby inhibiting the detrimental sulfate-reducing bacteria (SRB) population, which causes the generation of H2S. This deliberate and controlled modification of the microflora and reservoir ecology has been termed biocompetitive exclusion. This directed alteration of the microbial ecology is achieved by the introduction of a nutrient formulation that favorably influences the dynamics of the reservoir microflora. The treatment system does not require the addition of microbial cultures. Periodic well treatments have been shown to dramatically reduce or completely eliminate sulfide levels and establish control of the system in diverse field demonstrations supported by the U.S. Dept. of Energy. Field data in a variety of reservoirs will be presented that demonstrate the effectiveness of this new approach to treating and remediating wells with high levels of H2S. The versatility and low cost of this novel technology offers the petroleum industry a practical and cost effective methodology for the control of H2S in oil and gas wells.
Analyzing a Multilateral-Well Failure in the East Wilmington Field of California
Authors: Brister A. R.
Published: December 2007

As the industry pursues optimum cost drilling techniques, more focus is being applied to multilateral (ML) technology. The presently available literature invariably focuses on the cost and efficiency benefits of drilling ML wells. What is missing in the media, however, are the benefits associated with publication of the negative aspects or costly failures of higher-technology, multiple-lateral projects that require a mechanical tieback, cement, or a pressure seal at the junction of the laterals (i.e., Class 3-, 4-, or 5-type wells, respectively). This paper presents a case study of a Class 4 ML well attempted by THUMS Long Beach Co. in the East Wilmington field of California.
Effect of Pretest Pressures and Temperature on DST Interpretation
Authors: Johns R. T. , Ma Long
Published: December 2007

Drillstem tests (DST's) in porous media typically consist of a sequence of production and shut-in periods. Interpretations of DST's are often based on application of the Horner method to the shut-in periods. Such an analysis assumes that the wellbore rate is constant during the production period and that the pressure response during the shut-in is affected only by that production period. For many DST's, however, these assumptions are no longer valid and other interpretation methods are required. For example, prior production and shut-in periods and/or pretest pressures can significantly affect the pressure response of subsequent periods and cause erroneous parameter estimates.

In this paper, we present a new DST semianalytical solution that can account for the effect of pretest pressures, prior test periods, wellbore temperature variations, and other factors such as wellbore storage and skin on the pressure response. The solution is an extension of the solution presented by Correa and Ramey1 who derived a DST solution by writing a single time-dependent wellbore boundary condition. Application of the new solution to example DST data shows that estimates of formation pressure from the Horner analysis can deviate from the true formation pressure by several hundred psia, whereas permeability estimates can differ by a factor of two or three.
Pressure-Volume-Temperature Correlations for Gulf of Mexico Crude Oils
Authors: Petrosky G. E. , Farshad F.
Published: December 2007

New empirical pressure-volume-temperature (PVT) correlations for estimating bubblepoint pressure, solution gas-oil ratio (GOR), bubblepoint oil formation volume factor (FVF), and undersaturated isothermal oil compressibility have been developed as a function of commonly available field data.

Results show that these PVT properties can be predicted with average absolute errors ranging from 0.64% for bubblepoint oil FVF to 6.66% for undersaturated isothermal oil compressibility.
Waterflooding Performance Using Dykstra-Parsons as Compared With Numerical Model Performance (includes associated papers 6403 and 6404 and 6407 and 6411 and 6416 )
Authors: Mobarak Salem
Published: December 2007

Introduction

Multilayered models have been used by a number ofinvestigators to represent heterogeneous reservoirs.Standing et al. calculated coverage and defined thepermeability variation factor in their theoretical study permeability variation factor in their theoretical study of variable-permeability, retrograde-condensatereservoirs undergoing gas cycling. Dykstra and Parsonsadopted the fundamental ideas presented by Standinget al. and developed a method for estimatingwaterdrive coverage factors. Based on experimental datafrom a linear-layered model, Dykstra and Parsonsdeveloped correlation charts relating coverage tomobility ratio and permeability variation for differentwater-oil ratios (WOR). Another chart, based solelyon laboratory data, showed recovery modulus as afunction of coverage. The recovery modulus is givenby

(1)

where

R = fractional recovery of the original oil inplaceSwi = initial water saturationWOR = producing water-oil ratio

The steps used in the Dykstra-Parsons predictionsare outlined in their original paper. Johnsonproposed a simplified method for making proposed a simplified method for making Dykstra-Parsons predictions. He plotted permeabilityvariation against mobility ratio for lines of constantrecovery modulus as given in Eq. 1. Four charts wereconstructed for WOR's of 1, 5, 25, and 100, respectively. Both the Dykstra-Parsons and Johnson chartsshould give the same results. Another modified formof the Dykstra-Parsons method eliminated the needfor graphical correlation to calculate oil recovery.In this modified form, one proceeds with Steps 1through 4 of the standard Dykstra-Parsons methodto calculate coverage. Oil recovery is then computedas follows:

(NP/N) percent pore volume = C(1 - Sor - Swi)............................(2)

(NP/N) percent original oil in place =C(1 - Sor - Swi)/Soi,...................(3)

where

C = coverageSoi = initial oil saturationSor = residual oil saturationSwi = initial water saturationNP/N = fractional oil recovered

The purpose of this note is to present waterfloodperformance for multilayered systems using the performance for multilayered systems using the standard Dykstra-Parsons method as compared with thatpredicted by the modified form using Eqs. 2 and 3 predicted by the modified form using Eqs. 2 and 3 and those obtained by using a numerical model.

JPT

P. 113
Alaska -- Oil and Forget-Me-Nots
Authors: Chatterton C.V.
Published: December 2007

CHATTERTON, C.V., STANDARD OIL CO. OF CALIFORNIA, ANCHORAGE, ALASKA MEMBER AIME

The oil industry singularly provided major justification for Alaskan statehood and continues to play a responsible role in the State's very existence. One out of every three dollars of current State revenue is a direct oil dollar.Alaska offers a safe haven for oil investment, and leasing regulations provide incentive for exploration. The combination of Alaska's climate, terrain and remoteness presents a unique challenge to operators and makes the cost of doing business high. Air and water transportation plays an important role. Alaska's potential has barely been scratched. Offshore drilling offers new hope. Scheduled early completion of a refinery insures that Alaska will be a fully integrated oil state. Also, the State's natural-gas potential is great.

Introduction

Oil men everywhere are interested in Alaska. The frontiersman spirit is kindled by Alaska's everyday challenges. Indeed this spirit is required to encourage the continuing search for oil so necessary to convert this infant state into a major producer of hydrocarbons.Alaska got off to a flying start in 1957 with a major discovery, the Swanson River field. Nearly six years later, private enterprise is still looking for Alaska's second major oil discovery. The success ratio since then has been low; nevertheless, enthusiasm for the oil potential of this great state has been far from diminished. To date, the surface has barely been scratched.This paper reviews the infant years of the industry in Alaska. This baby is continuing to be fed at ever-increasing rates with exploration and development dollars. New operators are continuing to accept the challenge of drilling in Alaska. To better understand the challenge this infant faces, the environment into which the babe was born must be understood. This state is the land of the forget-me-not, Alaska's floral emblem which is the hallmark of friendship and fidelity. Alaska is an enormous, beautiful and challenging country. This is a land of long summer days with its floor carpeted in wild flowers and forget-me-nots.Alaska is vast. In aerial extent, it is nearly one-fifth as large as the "South 48," and with more coastline than the entire Continental United States. It is more than twice the size of Texas with less than 2 1/2 per cent of the population of Texas. In fact, the population density is 0.4 of a person/ sq mile, compared with 36.2 people/sq mile in Texas. The 0.4 figure includes 35,000 Indians, Aleuts and Eskimos out of a total population of 226,000.This thinly populated country is unique. Alaska desperately wanted to become a state. The promise of oil aided in making Alaska eligible for statehood. Quoting Alaska's Governor William Egan, "The discovery of oil was instrumental in providing an economic atmosphere favorable for Statehood".

Understanding Alaska

Geography

Geographically speaking, Alaska consists of over 375 million acres.

JPT

P. 471^
Advanced Sandstone-Acidizing Designs With Improved Radial Models
Authors: Gdanski R. D. , Shuchart C. E.
Published: December 2007

With the intent of encouraging and helping the reader to design a radial model tailored to a particular use, this paper discusses and describes radial models that have proved useful in exploring and simplifying the application of the kinetics of sandstone acidizing. With the recent development of a comprehensive theory for the complete chemistry and kinetics of sandstone acidizing, it was appropriate to develop useful radial models for exploring and simplifying the application of the new technology. These radial models were designed to accommodate both the positive and negative aspects of the recent discoveries. These discoveries included ion-exchange transformation of brines, decomposition of clays in hydrochloric acid, precipitation of fluosilicates, removal of carbonate to prevent the precipitation of complex aluminum fluorides (AlFx's), silica-gel filming, colloidal silica-gel precipitation, precipitation of the various complex AlFx's, mixing between the various stages of the treatment, damage removal, permeability modeling, and skin evolution. Calculations were initially performed with a comprehensive workstation-based computer model so that the magnitude of the various effects could be measured. These calculations showed that many negative effects could be minimized or eliminated by special design considerations. A PC-based model was then written that could help design engineers avoid serious problems when acidizing sandstone formations and provide them with visual guidance to some of the other issues that were relevant. This avoiding problems approach for the PC-based radial model provided a powerful basis for introducing advanced designs for sandstone acidizing that have dramatically improved the success rates of field treatments. In addition to choosing the correct HF fluid to avoid secondary precipitations, considerations for choice of preflushes to condition the formation proved essential. Proper choice of preflush is based on acid stabilities of the clays, carbonate removal, and the avoidance of deep clay swelling. Appropriate acid-preflush volumes help ensure carbonate removal for at least 24 in. and provide sufficient fluid spacing between formation brine and the spent HF fluids at the end of the treatment.
Analysis of Low-Temperature Separation Plants
Authors: Stamm H.E. , McCarty D.G. , Allen D.B. , Moore C.S.
Published: December 2007

A method for calculating the performance of low-temperature separation plants is discussed, and comparisons of calculated recoveries with those observed during field testing of an installation are shown. The ability to calculate plant performance is of considerable value as a variety of possible operating programs can be investigated at little cost.

The close agreement between calculated and observed plant recoveries suggests that with reasonable diligence plant performance can be calculated within generally accepted engineering accuracy. However, as over-enthusiastic employment of calculations can lead to serious error, calculated results should be supplemented with sufficient field or laboratory test data to provide adequate experimental verification.

Introduction

Within the past few years the use of low-temperature separation and stabilization units to increase the recovery of condensate from gas streams has increased greatly. Although the principle of cold separation is simple, the processing that is required to separate the hydrocarbon stream into the gas and liquid fractions resulting in the greatest over-all economy of operation is sometimes complicated, and the equipment used for this purpose is often expensive. Frequently, several hydrocarbon streams of varying (and in many cases, unknown) composition are mixed prior to processing through a plant. As a result, the most desirable operating conditions have not always been selected, and unexpected operating difficulties have developed.

It seems plausible that a better understanding of lowtemperature processing and removal of much of the aforementioned uncertainty can be achieved by replacing rule-of-thumb analyses with convenient and usable calculation techniques. Therefore, the discussion which follows is designed to demonstrate that liquid hydrocarbon recovery resulting from processing light hydrocarbon mixtures through the type of low-temperature and stabilizer equipment commonly encountered in the Gulf Coast area may be calculated with sufficient accuracy for many engineering purposes.
Bundle-Flowline Thermal Analysis
Authors: Zabaras G. J. , Zhang J. J.
Published: December 2007

The bundle flowline involves packaging multiple flowlines, control, and injection lines within a single carrier pipe. A bundle is claimed to provide an effective means of insulating flowlines by use of low-cost materials; however, no rigorous heat transfer analysis of bundled flowline systems has been offered by the literature or the vendors. For this reason, the thermal performance of bundle- insulated flowlines has been studied with a general-purpose, finite- element, partial-differential equation solver.

Steady-state and transient cooldown performance were analyzed for six different bundle configurations. Overall heat transfer coefficients for individual flowlines within a bundle have been determined in addition to cooldown performance for different insulation levels and pipe sizes. These results have been compared with results obtained for the simple bundle geometry of a pipe-in-pipe system, and found comparable.

To expedite the calculation of overall heat transfer coefficients for bundle flowlines, simplified heat transfer calculations were developed as an approximation to the finite-element solutions. These approximations are on the average within 5% of the finite- element solution.
Flexible Bit: A New Antivibration PDC-Bit Concept
Authors: Defourny P. M. , Abbassian Fereidoun
Published: December 2007

This paper introduces the novel concept of a flexible polycrystalline diamond compact (PDC) bit and demonstrates its capability to reduce detrimental vibration often associated with drag bits. The tilt flexibility, introduced at the bit, decouples the dynamic motion of the bottomhole assembly (BHA) from that of the bit, thus providing a dynamically more stable bit. The paper describes the details of a prototype 8½-in. flexible bit design, laboratory experiments, and field tests, which verify the concept.
Cement Design Based on Cement Mechanical Response
Authors: Thiercelin M. J. , Dargaud Bernard , Baret J. F. , Rodriquez W. J.
Published: December 2007

The disappearance of cement bond log response as a result of variations of downhole conditions has been observed in numerous wells. This observation has led to concern about the loss of proper zonal isolation. Stresses induced in the cement, through deformation of the cemented casing resulting from the variation of down-hole conditions, are the cause of this damage.

We present an analysis of the mechanical response of set cement in a cased wellbore to quantify this damage and determine the key controlling parameters. The results show that the thermo-elastic properties of the casing, cement, and formation play a significant role. The type of failure, either cement debonding or cement cracking, is a function of the nature of the downhole condition variations. This analysis allows us to propose appropriate cement mechanical properties to avoid cement failure and debonding. We show that the use of high compressive strength cement is not always the best solution and, in some cases, flexible cements are preferred.
Development of Services and Equipment for Small Holes
Authors: Huber T.A.
Published: December 2007

The New Proven Small-Hole Completion

As a result of slim-hole development, small holes can now be drilled and completed with 4½-in. OD casing at a savings up to 35 per cent over conventional well sizes. This economical completion is illustrated as the "1954" completion in Fig. 1. Important advances in drilling tools and techniques have resulted in drilling rates for these small holes which are comparable to rates for larger holes. Savings from employing smaller and more economical drilling equipment and reductions in casing tonnage, coupled with advances in completion technology, are effecting a size reduction such that 4½-in. OD casing set in holes from 5 5/8 in. to 6 1/8 in. in diameter and completed with 2-in. tubing is growing in acceptance.

Although certain calculated risks are taken, experience has indicated that the incidence of fishing operations should not exceed that experienced in holes of conventional size, provided the usual precautions are taken. Furthermore, fishing for such items as drill collars and bits should be limited in light of the economics of sidetracking and redrilling the inexpensive small hole. Savings in exploration and development costs adequately compensate for the slight risk involved. These holes for 4½-in. casing may be drilled, fished, logged, completed, produced, and reworked without undue difficulty.

Equipment for Drilling and Completing Wells with 4½-in. OD Casing

Recently, important improvements have been made in drilling tools and techniques for these small holes. Bearings in 5 5/8-in. and slightly larger rock bit sizes have been improved. This, coupled with the introduction of long-tooth, soft formation bits, has resulted in drilling rates for these holes being comparable to larger holes. In addition, diamond or similar type drilling and full-hole coring become increasingly effective with reduction in hole size.

Several good rig designs for this small-hole work are offered by manufacturers, but such rigs are not widely available for contract drilling. The universal rig design is as unattainable here as for larger holes; but in most cases, a unitized trailer-mounted slim-hole rig which does not require guy wires is very desirable because of portability and speed. In some areas available lightweight, large-hole rigs may be profitably used in slimhole drilling to greater depths; and in other areas, special design considerations for restricted highway loading may be desirable.
Some Experiments on the Flow of Miscible Fluids of Unequal Density Through Porous Media
Authors: Crane F.E. , Kendall H.A. , Gardner G.H.F.
Published: December 2007

Introduction

Craig, et al investigated the effect of gravity on frontal displacements for circumstances in which the gravity forces were significant. Blackwell, et al, dealt with the other extreme in which gravity forces were negligible. The considerable difference between their results is illustrated in Fig. 1 where the breakthrough recoveries are plotted against the mobility ratio. The experiments described in the present paper were conducted to examine how the transition from the one extreme case to the other occurs when the gravity forces are gradually reduced.The transition is well illustrated by the production history after breakthrough. Fig. 2 shows how the number of pore volumes which must be injected at a constant rate to displace 98 per cent of the original fluid depends on the gravity force. For each mobility ratio there is a transition range, and a very significant change in the number of pore volumes occurs when this range is transversed. This range of the gravity force is physically linked withtheformationofviscousfingers.A single finger is predominant for larger gravity forces; a multiplicity of fingers is formed for smaller gravity forces. Improved recovery and the occurrence of multiple fingers is concomitant with a large increase in the amount by which the fluids are mixed within the porous medium.The transition range depends on all the dimensionless groups which characterize the problem; but this dependence has not been exhaustively studied as yet and only fragmentary results are discussed in this paper.

SPEJ

P. 277^
Effect of Pressure, Temperature and Wellstream Composition on the Quantity of Stabilized Separator Fluid
Authors: Portman W.E. , Campbell John M.
Published: December 2007

A series of correlating charts have been prepared to enable the field engineer to predict the amount of stock tank fluid produced by stabilization of first stage separator fluid. The charts shown are particularly convenient for estimating the relative effect of temperature and pressure in economic studies. Further work is planned to investigate the factors affecting stage separation to supplement this preliminary work.

The direct correlation of separation variables is dictated as a convenience to eliminate the trial and error calculation necessary when using the standard flash vaporization equations. These are obtained by a material balance using the equilibrium vaporization ratio K, and have appeared in the following, or similar, form many times in the literature.

These equations may of course be effectively and accurately solved by use of digital and analog computers. However, these are not usually readily available in field offices and the need often arises for fast results during routine operational problems. Consequently, many methods have been devised in an attempt to simplify the basic calculation.

The methods proposed are generally satisfactory, but do not eliminate trial and error methods and the necessity of subsequent calculations to obtain the answer in volume terms. The purpose of this work, therefore, was to develop accurate charts that would give the result directly in gallons.

When using stage separation the recoveries would be lower than those shown, for stabilization usually gives about 95+ per cent recovery on the potential stock tank components in the separator liquid.

The recoveries are shown in terms of a 14 psi Reid Vapor Pressure product which has a true vapor pressure of 14.7 psia at 98°F. Consequently, this product represents a stable stock tank liquid under normal storage conditions.

To estimate natural gasoline recoveries by stabilization the volume shown may be multiplied by 1.20 for 18 lb RVP natural gasoline and 1.36 for 26 lb RVP natural gasoline.
Characterization of a Gas Well From One Flow-Test Sequence
Authors: Odeh A.S. , Moreland E.E. , Schueler S.
Published: December 2007

Most acceptable methods of gas well characterization require a series of drawdown-buildup sequences. The method described here requires only one drawdown followed by a buildup, thus reducing testing time and associated costs.

Introduction

Many authors recognize that Darcy's law may not hold for flow of gas through porous media. The non-Darcy flow effect has been accounted for by a flow-rate-dependent skin. Thus, to adequately characterize and predict deliverability of a gas well, it is essential to resolve the skin calculated from a buildup or a drawdown into at least its two components: the physical or rate-independent component, and the nondarcy, or rate-dependent component. The total skin calculated from flow tests has been represented by the following equation.

st = s + Dq,................................(1)

where

st = total skin calculated from flow tests

s = skin caused by physical damage or improvement, plus pseudoskin effects caused by restricted entry to flow at the wellbore

D = nondarcy flow constant in 1/q

q = gas flow rate in any appropriate units.

Basically, there are two methods for estimating the non-Darcy flow constant, D. The first method calculates D by the following equation.

-15 2.715 × 10 M pbk D =, ...............(2) hr w T b

where 1 D = Mscf

M = molecular weight of gas, lb

P = base pressure, psi

k = permeability, md

mu = viscosity, cp

h = thickness, ft

r = wellbore radius, ft

T = base temperature, deg. R

beta = turbulence factor, 1/ft.

beta may be estimated theoretically by -5/4 -3/4 beta = (5.5 × 10) k (phi S),

where

phi = porosity, fraction

Sg = gas saturation, fraction.

The second method uses flow tests to calculate D. The literature reports that comparing values of D estimated by Eq. 2 with those obtained from flow-test data indicates that the theoretically determined values may be in error by as much as 100 percent. Because of this uncertainty, D should be obtained from flow tests when possible.

JPT

P. 1500
Development of a Local Grid-Refinement Technique for Accurate Representation of Cavity-Completed Wells in Reservoir Simulators
Authors: Göktas Baris , Ertekin Turgay
Published: December 2007

In this paper the development of a three-dimensional, single-, and two-phase fluid flow model to study flow performances of cavity-completed wells is presented. A static local grid refinement (LGR) is embedded into the model in order to adequately capture the flow behavior around cavity completions using a reasonable number of grid cells. The model adopts an approach that is significantly different from the current practice in which cavity-completed wells are incorporated into computations by assigning large wellbore radii and/or large negative skin values to a conventional wellbore model.

The model utilizes the residual equation rather than a wellbore equation to determine the flow into cavity-completed wells. Cavity-completed wells are described as a collection of fine rectangular grid blocks. This representation is referred to as the cavity approach. The constructed fine grid lines are terminated at the coarse/fine grid block interfaces by implementing the LGR technique developed. The technique subdivides selected coarse grid blocks into fine rectangular grid blocks in all three dimensions that are known as window blocks. The flow equations generated for window and coarse grid cells are then solved simultaneously by using the preconditioned biconjugate gradient stabilized iterative method.

First, a radial-cylindrical wellbore is approximated using the cavity representation. The model results from single phase, slightly compressible fluid flow simulation with the cavity approach are, then, compared against the analytical solutions. In these comparisons, very good matches are obtained for both flow rate and sandface pressure specifications at the wellbore. The model is further extended to single phase, compressible, and two-phase fluid flow conditions in both conventional and coalbed reservoirs. The model results are, in this case, compared with the existing numerical models that utilize Peaceman's wellbore model. Again, close agreement in flow response is obtained for a series of comparisons. Finally, the cavity approach is tested by modeling flow performances of irregularly shaped, cavity-completed wells in conventional and coalbed reservoirs.

During the creation of cavity completions in coal seams, it is hypothesized that fracture networks in certain directions are generated around cavities. The effects of fractures are usually incorporated into a simulation study by modifying the permeability values around the wellbore. The cavity approach presented in this paper provides not only a better approximation to the shape of the cavity but also a better representation of the altered permeability values around the cavity since fine grid cells are already in place around cavity completions.
Field Application of a Scale Inhibitor Squeeze Enhancing Additive
Authors: Collins I. R. , Cowie L. G. , Nicol M. , Stewart N. J.
Published: December 2007

Barium sulfate scale deposition in the near wellbore, perforations, or production tubing has severely affected well productivity in many North Sea Fields. This is due to the co-mingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular "squeeze" deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical.
Prediction of Oil Production Rate of Jet Pumping Oil Wells From Sample Well Data
Authors: Shtoff A. V.
Published: December 2007

The method of accurate prediction of the oil production rate of jet pumping oil wells from sample data is considered. This method can be easily programmed for computer and used by field operators to refine test results.
Calibration of Casing/Tubing Design Criteria by Use of Structural Reliability Techniques
Authors: Adams A. J. , Hodgson T.
Published: December 2007

This paper reviews the state-of-the-art in casing/tubing structural reliability analysis, and the knowledge gained from it to date. Results are presented to show that, as previously suspected, burst design based on casing full of gas is over-conservative for non-critical wells. However, the risk-calibrated design criteria are strongly dependent on the design philosophy for underground blowout loads. It is demonstrated that well control is the largest single factor in reducing risk; gaps in current knowledge are identified, and recommendations made for future work.
Factors Influencing Optimum Ball Sealer Performance
Authors: Brown Robert W. , Neill George H. , Loper Raymond G.
Published: December 2007

Introduction

The perforation sealing process has been proven highly successful and economical since it was introduced to the oil and gas industry in early 1956. Since it has proved so successful in multistage fracture treatments at a much lower cost than conventional packers, the ball sealer process has become a byword in well completions." Not only has it changed the design of fracture treatments, it has changed the concepts of selectively perforating and has greatly aided the success of the single-point and limited- entry techniques."Yet with all the advantages, there are still facets of ball sealer behavior that are not widely recognized. These must be known and understood to better design and execute the optimum ball sealer treatment.The down-hole behavior of ball sealers is influenced by a number of factors including an "inertial force", a "drag force" and a "holding force". These are considered in two phases-the initial seating of the ball and the forces tending to unseat the ball after contact has been made (see Fig. 1 ).This paper presents a theoretical study of these factors and formulas for predicting their influence. The authors acknowledge the fact that the flow equations presented herein describe the behavior of Newtonian fluids and do not cover the so-called power-law fluids. The assumptions made, however, are reasonable and well within practical limitations of the conditions encountered during field application. For example, it is assumed that the perforations are round with a discharge coefficient of 0.82. While this may not be exactly true, it has been verified within practical field limitations.' The discharge coefficient would not vary significantly even if the perforation size or configuration varied pronouncedly. The approach of assuming uniform perforation size is not as strained as it might first appear. Normally, a perforator contains charges equally spaced with the same number in each vertical (or horizontal) plane. If the perforating gun is not centralized, the holes in one plane will be smaller than average, while the holes in opposing planes will tend to be larger than average. The net result is that the two effects tend to balance.

FACTORS AFFECTING CONTACT WITH PERFORATION

Ball sealers are injected into well treating fluids for the purpose of contacting and sealing those perforations which are accepting the fluid flow. The efficiency of the sealers is primarily influenced by:the velocity of the balls down the pipe, andthe fluid velocity through the perforations.

To divert the sealer to the perforation, the inertial force of the ball must be overcome by the drag force created by the fluid velocity through the perforation.

BALL VELOCITY

The final, or stable, velocity of the ball is the sum of the actual fall velocity and the fluid velocity.

JPT

P. 450^
Analog Study of Water Coning
Authors: Meyer H.I. , Searcy D.F.
Published: December 2007

Introduction

The analysis of our previous paper on the behavior of two immiscible fluids separated by gravity into two distinct saturated zones in the porous medium was shown to be theoretically valid only if one of the two fluids was immobile. The practical problems associated with flow of both phases have so far been impossible of solution by these analytic methods. We, therefore, decided to resort to a simulator study to answer the following pertinent questions:If the lighter fluid is produced from a point above the fluid-fluid interface, how long will it take for the heavier fluid to come up to the point where production of both fluids is taking place?After steady-state two-phase production is established, what is the relative production rate of each phase, on what physical variables does this depend, and what are the boundary conditions at the outflow face?A third question was at least partially answered in the course of this investigation: that of the shape of the interface under flow conditions. These questions are of fundamental importance in the fields of hydrology and the reservoir mechanics of oil and gas production.

In order to simplify equipment used and still retain a fair physical representation of these phenomena, it was decided to use a Hele-Shaw type of analogy in which the flow took place between two vertically mounted pieces of plate glass. The advantage of this system is that it eliminates any surface effects between the matrix of the porous medium (e.g. packed sand) and also allows equilibrium conditions to be established more quickly. The principle disadvantage (apart from the obvious one of being one more step removed from the prototype) is that our equipment limited us to two dimensional flow studies.

In spite of these limitations answers to the questions were obtained which seem adequate for our purposes. We would like to see more work of this nature done to verify and to improve our conclusions.
Analysis of Wireline Formation Test Data from Gas and Non-Darcy Flow Conditions
Authors: Kasap Ekrem , Lee Jaedong
Published: December 2007

Unlike liquid formation tests, in a gas formation test, both compressibility and viscosity vary with pressure, and non-Darcy flow is more likely. In this study, the gas formation rate analysis technique is developed to analyze gas pressure tests. We calculated gas pseudopotentials, utilized the geometric factor concept, and replaced Darcy's equation with Forchheimer's equation to study non-Darcy flow effects. The technique is applied to a field test, and the results are verified by history matching it with a three- dimensional near wellbore simulator.
Targeting Horizontal Wells—Efficient Oil Capture and Fracture Insights
Authors: Tank W. J. , Curran B. C. , Wadleigh E. E.
Published: December 2007

Horizontal well targeting is often a greater challenge in massive, fractured carbonates than in low-productivity, poorly connected, and relatively thin reservoirs. This paper discusses methods to target horizontal wellbores in three-dimensional space to both confirm the fracture interpretation and establish high-efficiency oil capture. Several well examples are presented to illustrate the targeting objectives and the resulting well performance. Early in the program, the horizontal drilling objectives sought to maximize the lateral length in a direction determined by offset well productivity; the sample philosophy as is used in matrix-dominated reservoirs. Analysis of these results and employment of methods presented in this paper indicate profit can be maximized by drilling to a specific target to intersect a fracture trend at an optimum elevation instead of concentrating on maximizing length of lateral. Intervals of rapid penetration, lost circulation, and/or bit slides, along with cutting sample compositions, provided insight for confirmation and extension of the fracture network interpretation. The width of disturbance and degree of fracturing observed along interpreted fracture trends are valuable data for improved fracture network interpretation and computer simulation. Both the elevation and number of fracture branches encountered are significant strategic planning issues for oil recovery from unconfined oil columns in a massive carbonate system. Results from a large number of horizontals indicate significant productivity increases are achieved by proper targeting of laterals into major fracture features.
Evolution of the Global Decommissioning Regulatory Regime
Authors: Griffin William S.
Published: December 2007

This paper discusses the evolution of the global and regional Regulatory Regime for the decommissioning of disused oil and gas production platforms and other installations. The last part of this paper puts the regulatory aspects of the issue discussed into context.
The Shifting Center of Petroleum Production
Authors: Moody Graham B.
Published: December 2007

Introduction

During the past 98 years the United States has produced annually more crude oil than any other country, except during one three-year period and another period of four years. Needless to say this nation has surpassed all others in cumulative production.

The United States for many years has produced a greater percentage of its proved reserves annually than has any other country with large reserves. The high annual withdrawal from reserves by this nation in the past may lead in the future to the loss of its status as center of crude oil production.

Center of Annual Production

Rumania, birthplace of the oil industry, was the center of crude oil production during the three-year period, 1857 to 1859 (Fig. 1 and Table 1). Actually, it had the only recorded output in 1857 and 1858 and 67 per cent of world production in 1859. Before continuing the citation of honors as center of world's production, it should be mentioned that there may have been small production from some spot before records were kept.

The United States was largest producer from 1860 through 1897. U.S.S.R. took the lead from this nation in 1898 and held it through 1901. However, the United States regained the front position in 1902 and has not been overtaken since then. Since the first year of its supremacy, 1860, the United States has produced 50 per cent or more of world's production every year with these exceptions: 1898 to 1902, inclusive, 1953 and 1954. During the period 1907 through 1947 thenation's output was over 60 per cent of world's production each year, and in six of the years it produced 70 per cent or more of world's total.

There are several countries that should not be ignored despite the fact that they have not led the world as yet in production any year. A comparison of the maximum annual production of each of nine countries and the same year's production of the other eight countries is shown in Table 2. (See Fig. 2 also.) Six of the cited countries registered their maximum annual production in 1954. Probably all of these could produce more than they did in 1954. The percentage of the world's 1954 production credited to Iraq, Kuwait, and Saudi Arabia - and the known potentialities of these countries and Iran - suggest the direction in which the center of production is moving.
Andrew Well-Engineering Alliance: A New Industry Model
Authors: Gomersall S. D. , Klein R. J. , Clark Graham , Sneddon Ian , Simpson Michael
Published: December 2007

The BP Andrew field has been developed using a novel business solution which required the creation of a Well Engineering Alliance with shared objectives, a radically new behavioral approach and jointly developed targets.

The paper describes the structure of the Alliance, the development and implementation process and the success that has been achieved.

A project update provides a summary of subsequent progress.