bluuebunny/crossref_metadata_2025 huggingface dataset:
Paraffin Problems in Crude Oil Production And Transportation: A Review
Authors: Misra Sanjay , Baruah Simanta , Singh Kulwant
Published: December 2007

Problems related to crystallization and deposition of paraffin waxes during production and transportation of crude oil cause losses of billions of dollars yearly to petroleum industry. The goal of this paper is to present the knowledge on such problems in a systematic and comprehensive form. The fundamental aspects of these problems are defined, and characterizatin of paraffins and their solubility tendencies have been discussed. It has been established conclusively that n -paraffins are predominantly responsible for this problem. Comprehensive discussion on the mechanism of crystallization of paraffins has been included. Compounds other than n-paraffins, especially asphaltenes and resins, have profound effects on solubility of n-paraffins. In evaluations of the wax potential of a crude, the climate of the area concerned should be considered. Under the most favorable conditions, n-paraffins form clearly defined orthorhombic crystals, but unfavorable conditions and the presence of impurities lead to hexagonal and/or amorphous crystallization. The gelation characteristics are also affected the same way. An attempt was made to classify the paraffin problems into those resulting from high pipeline pressure, high restarting pressure, and deposition on pipe surfaces. Fundamental aspects and mechanism of these dimensions are described. Wax deposition depends on flow rate, the temperature differential between crude and pipe surface, the cooling rate, and surface properties. Finally, methods available in the literature for predicting these problems and evaluating their mitigatory techniques are reviewed. The available methods present a very diversified picture; hence, using them to evaluate these problems becomes taxing. A top priority is standardizing these methods for the benefit of the industry.
A Software System for Oilfield Facility Investment Minimization
Authors: Ding Z. X. , Startzman R. A.
Published: December 2007

Minimizing investment in oilfield development is an important subject that has attracted a considerable amount of industry attention. One method to reduce investment involves the optimal placement and selection of production facilities. Because of the large amount of capital used in this process, saving a small percent of the total investment may represent a large monetary value.

The literature reports algorithms using mathematical programming techniques that were designed to solve the proposed problem in a global optimal manner. Owing to the high-computational complexity and the lack of user-friendly interfaces for data entry and results display, mathematical programming techniques have not been given enough attention in practice. This paper describes an interactive, graphical software system that provides a global optimal solution to the problem of placement and selection of production facilities in oilfield development processes. This software system can be used as an investment minimization tool and a scenario-study simulator.

The developed software system consists of five basic modules: (1) an interactive data-input unit, (2) a cost function generator, (3) an optimization unit, (4) a graphic-output display, and (5) a sensitivity-analysis unit.

We used data from both onshore and offshore oil fields to test the performance of the developed system. We obtained significant reduction of computer run time and memory storage. Use of this system saved several million dollars in investments. These results show that the developed system can be applied where significant investments in offshore and/or onshore field developments are involved.
Modeling a Fractured Well in a Composite Reservoir
Authors: Chen Chih-Cheng , Raghavan Rajagopal
Published: December 2007

We develop a new model for a fractured well producing a composite reservoir. In this model, the vertical fracture may transect the inner zone of the composite-reservoir system. Computational issues are addressed so that the development given here becomes a practical tool. We examine results pertaining to systems in which damage is deep to demonstrate the utility of the model.
Generalization of the API RP 14E Guideline for Erosive Services
Authors: Shirazi S.A. , McLaury B.S. , Shadley J.R. , Rybicki E.F.
Published: December 2007

The commonly used practice for controlling sand erosion in gas and oil producing wells is to limit production velocities following the API RP 14E. This guideline contains a procedure to calculate a threshold velocity, the flow velocity below which an allowable amount of erosion occurs. While providing advantages of computational ease, the approach has some disadvantages. One is that, while many factors influence the erosion rate, RP 14E includes only one factor, the density of the medium. Thus, factors such as flow geometry, type of metal, sand size, and Reynolds number are not accounted for. Another disadvantage is that the tolerable amount of erosion, in terms of loss of wall thickness, is not specified in RP 14E. A method is presented to overcome these disadvantages by (1) accounting for many of the physical variables in the flow and erosion processes and (2) including a way to predict the maximum penetration rate for sand erosion. The capabilities of the method are evaluated by comparing predicted penetration rates with experimental data found in the literature.

In this paper, the method is applied to calculate threshold velocities. The computational procedure allows an allowable amount of erosion to be specified in mils per year for elbows, tees and direct impingement geometries. Threshold flowstream velocities are calculated for carrier fluids of crude oil, water, and methane at elevated pressure. Resulting threshold velocities are presented for a range of sand sizes, pipe diameters, sand production rates, and methane pressures. Results show that threshold velocities for single phase gas flows are much lower than threshold velocities for single phase liquid flows.

Introduction

Sand erosion is a major problem in many production situations because small amounts of sand entrained in the produced fluid can result in significant erosion and erosion/corrosion damage. Even in "sand free" or clean service situations where sand production rate is as low as a few pounds per day, erosion damage could be very severe at high production velocities. Sand erosion can also cause localized erosion damage to protective corrosion scales on pipe walls and result in accelerated erosion/corrosion damage.

The objective of this work is to develop guidelines for predicting a threshold velocity and/or particle size below which only a small, allowable amount of erosion occurs. Threshold velocity guidelines help operators to estimate safe production velocities in erosive services, and serve as a tool to engineers for the cost effective design of piping systems, the selection of piping materials, and the selection of appropriate screen sizes for new wells.
The Use of Coiled Tubing During the Wytch Farm Extended Reach Drilling Project
Authors: Summers Tim , Larsen Henrik Aslak , Redway Mark , Hill Gardiner
Published: December 2007

The largest onshore oilfield in Western Europe is situated in an environmentally sensitive coastal area on the south coast of England. Initial development of the field in the late 1970's focused on accessing reserves underlying the onshore section of the reservoir. In 1989, various development options were screened to access the offshore section of the reservoir, containing some 80 million barrels of recoverable oil. In 1991, the decision was made to access these reserves through extended reach drilling (ERD) from an existing onshore well-site. This development is currently underway, with three out of a planned eleven wells already drilled and producing.

This paper will describe the application of Coiled Tubing in the logging and completion phases of the ERD wells drilled to date, including:-Operational details of Coiled Tubing deployed cement evaluation logging suites to a measured depth of 5,695m (18,685ft) at a horizontal departure of 4,950m (16,241ft), and a cased-hole vertical seismic profile to a measured depth of 4,391 m (14,330ft) at a horizontal departure of 3,800m (12,468ft).Operational details of Coiled Tubing use during the completion; setting/pulling plugs, shining sliding sleeves, sand/debris clean-outs, including novel tool and procedural developments.Results of predictive modelling to assess the point of helical lock-up, and comparisons of field data with these predictions.Details of operations involving the use of friction reduction chemicals to enhance Coiled Tubing penetration.The effects of ERD well tangent section angle on Coiled Tubing penetration.

Conclusions are made as to the value of Coiled Tubing in ERD wells to minimise rig time and the current limits of technology.

Introduction

Wytch Farm is the largest onshore oilfield in Western Europe, and is situated on the southern coast of England, approximately 100 miles south west of London. The main reservoir lies under Poole Harbour, extending offshore under Poole Bay (Figure 1), and is in an Area of Outstanding Natural Beauty with Sites of Special Scientific Interest and Special Protection Areas, noted for its landscape, ecology and amenity value.

The field was discovered in 1974, and the majority of production comes from two oil bearing sandstone formations.
Stability of Displacement Fronts in WAG Operations
Authors: Virnovsky George A. , Helset Hans Martin , Skjaeveland Svein M.
Published: December 2007

This paper presents an analytical and numerical study of the stability of gas-oil-water displacement fronts in two spatial dimensions. The flow equations are simplified by averaging in the dip-normal direction assuming vertical equilibrium to give analytical expressions for three-phase pseudo relative permeabilities and capillary pressures for a stratified reservoir.

A similarity transform results in a set of two coupled, ordinary differential equations and a simple technique is presented to identify the traveling-wave solution when certain conditions are met, and the shape of the front is calculated. The technique is based on an analysis of initial and boundary conditions and is verified by numerical simulation.

Dietz's classical stability theory for two-phase displacement fronts has recently been extended to layered reservoirs. To our knowledge, the present paper is the first to treat three-phase flow. It is shown that stable water-oil-gas fronts occur only for a limited number of the injection gas-water ratio, if at all.
An Inexpensive Mud for Deep Wells
Authors: Coffer Henry F. , Clark Roscoe C.
Published: December 2007

Development of a new mud designed to give the desirable drilling characteristics of the conventional lime mud but without its inherent limitations is discussed. The work includes both laboratory and field testing of the mud.

The mud has been used successfully in nine wells with considerable cost reduction. It is resistant to contaminants such as anhydrite, gyp, cement, and salt water and does not gel at high temperature. Field results have shown that the mud can compete economically with low- or high-pH caustic-quebracho muds with the added advantage that it yields better gauge holes and its filtrate is not as damaging to the pay formation.

Introduction

The use of conventional lime-base drilling muds has made possible the drilling of wells in areas where contamination from gyp, anhydrite, and salt water flows are encountered. Their desirable drilling characteristics and ease of maintenance have allowed the drilling of long sections of open hole and have often eliminated the necessity of a protective intermediate casing string. Conventional lime muds, however, suffer from several disadvantages which often make their usage impractical.

First, and of greatest importance in deeper holes, is the occurrence of high temperature gelation which prevents the successful application of various logging tools and perforating guns due to the solidification of the mud in the bottom of the hole. Further evidence of this gelation of conventional lime muds will be more apparent in the near future as workover jobs require washover operations in order to pull the packers set in lime mud.

Of almost equal importance is the high cost of the maintenance of a lime mud. This eliminates or sharply curbs its usage in areas where contamination from gyp, anhydrite, and salt is light enough that it can be successfully handled by use of low-pH or high-pH caustic-quebracho muds. Unfortunately, its elimination from a cost standpoint also limits the use of muds with filtrates containing calcium ion which is effective in reducing the swelling and sloughing of shales, thus yielding better gauge holes.
Active Damping of Torsional Drillstring Vibrations With a Hydraulic Top Drive
Authors: Jansen J. D. , van den Steen Leon , Zachariasen Erik
Published: December 2007

This paper describes the development and field testing of a new active-damping system to eliminate "stick/slip" torsional drillstring vibrations. The system controls the energy flow through a hydraulic top drive and makes the top drive react as a tuned vibration damper. The control algorithm, outlined in the paper, was implemented in software in the electronic control system for the pump unit of the top drive. Dedicated workshop testing allowed for a rapid installation at the rigsite. The system was field tested in a deep exploration well in the Barents Sea and contributed to excellent coring performance by eliminating torsional vibrations while coring hard limestone.
Produced-Water Reinjection and Fracturina in Prudhoe Bay
Authors: Martins J. P. , Murray L. R. , Clifford P. J. , McLelland W. G. , Hanna M. F. , Sharp J. W.
Published: December 2007

This paper presents an analysis of approximately 159 injectors from the Prudhoe Bay oil field that were subjected to periods of injection with seawater, produced water, and miscible injectant (MI) over a 10-year period. The long-term effects on injection performance of produced-water quality, fluid temperature, fracture growth, well trajectory, and other factors are quantified.
An Evaluation of New Aspaltene Inhibitors; Laboratory Study and Field Testing
Authors: Bouts M.N. , Wiersma R.J. , Muijs H.M. , Samuel A.J.
Published: December 2007

Three candidate asphaltene inhibitors have been laboratory tested for their effectiveness on a Canadian crude. One inhibitor, an oil-soluble polymeric dispersant developed by Shell Chemicals, showed superior behaviour compared to the others: flocculation titrations with n-heptane resulted in an optimum concentration of 1300 ppm. PVT calculations, however, indicated that the prevailing conditions downhole can be quite favourable with respect to the amount of effective inhibitor compared to the atmospheric laboratory titrations which appear to be quite severe tests. Therefore, lower initial concentrations were recommended for a field trial. The chemical could be continuously injected through a capillary string, thereby avoiding the lost oil production associated with solvent cleaning operations. It has proved to be very effective at concentrations as low as 66 ppm, resulting in both a technically and an economically successful trial.

Introduction

Precipitation of asphaltenes in reservoirs, wells and facilities has a severe detrimental impact on the economics of oil production because of a reduction well productivity and/or clogging of the production facilities. The nature and behaviour of asphaltenes in crude oils is complex. Asphaltenes are heterocyclic macromolecules mainly consisting of carbon and hydrogen and minor components such as sulphur, nitrogen, and oxygen. It is generally accepted that resins and maltenes (these structures are comparable to asphaltenes but with a much lower molecular weight) are responsible for keeping the asphaltene particles in dispersion. The asphaltenes are surrounded by the polar head groups of the resins and maltenes while the nonpolar alkyl tails interact with the oil phase. So, crudes with a high ratio of resins to asphaltenes are less subject to asphaltene deposition whereas crudes with large amounts of non-polar saturates compared to aromatics are more prone to exhibit asphaltene precipitation problems. At "normal" reservoir conditions the asphaltenes, resins, maltenes and oil phase are in thermodynamic equilibrium. This equilibrium can be disturbed by a number of factors: decline of the reservoir pressure towards the bubble point, change in temperature or addition of a miscible solvent to the oil as applied in various EOR techniques.

Much research has been focused on modelling the deposition behaviour of asphaltenes in reservoir crudes upon changes in pressure, temperature or composition. These models are based on the Flory-Huggins theory for colloidal systems and calculate the chemical potential for large molecules in the various phases. They require solubility parameters as input. In addition, the industry has made a substantial effort to develop pragmatic solutions to the problem of asphaltene deposition in producing wells.
The Use of Open Flow Potential Test Data in Determining Formation Capacity and Skin Factor
Authors: Essis B. A.E. , Thomas G.W.
Published: December 2007

Introduction

A knowledge of formation flow capacity and damage is necessary to determine reliable values of gas well deliverability. This information is usually acquired by pressure buildup or drawdown tests. However, in low-permeability reservoirs, the long time required to conduct such tests is frequently prohibitive. For this reason attention has been directed toward employing variable-rate tests that do not require well shut-down. In 1965, Odeh and Jones developed a generalized variable-rate procedure that can be used to analyze four-point backpressure data from gas wells. This procedure makes it possible in some cases to obtain formation flow capacities from backpressure surveys without resorting to further well tests. Since data from such surveys are frequently available, an evaluation of the Odeh-Jones technique is needful.

Fraser attempted to use the Odeh-Jones technique to predict gas well deliverability in West Texas reservoirs. He found the method useful for detecting invalid backpressure test data. For long-term prediction of gas well deliverability, however, the results he obtained were not satisfactory. He concludes that this could be attributed to "problems in basic data rather than failure of the theory". Fraser's study is limited by the assumptions of small pressure gradients and gas ideality; further, he made no comparisons with results obtained from drawdown or buildup tests.

In this work, using real gas theory, we present the results of an Odeh-Jones analysis of backpressure test data from 16 new gas wells. Flow capacities so derived are compared with those obtained from pressure buildup tests. We have tried to categorize the wells and interpret observed anomalies in terms of formation characteristics within each category, and to delineate where the technique is applicable. Also, we demonstrate the importance of using real gas flow theory and obtaining reliable test data.

ProcedureProcedure Development of Equations

In the treatment of isothermal flow of gases through porous media, it has been standard practice to assume that the gas is ideal to the extent that viscosity and the gas law deviation factor z remain constant. This gives rise to flow-rate expressions that involve squared pressure terms. For example, the pressure drawdown for radial gas flow at constant rate in an infinite system is described by

(1)

where m = 1,637 zT/kh, s = log (kpi/ rw2) − 3.23+0.87 s, and D is the Ramey non-Darcy flow constant, and log t means log10 t. (Eq. 1 is presented in a form slightly different from that given in Ref. 1 For details, see the Appendix.)

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A Solution to Ground Subsidence Problems In Casing Strings and Wellheads
Authors: Burley J.D. , Drouin Andre H.
Published: December 2007

A new wellhead assembly and method for restoring casing string tension provides a fast, economical solution to well problems created by ground subsidence. The new design permits one man, using simple and easily transportable equipment, to make casing string tension corrections rapidly and with minimum interruption of well production.

Introduction

Subsidence has produced buckling of casing strings and wellhead failures due to force reversals in the production casing strings of oil and gas wells. Detection of active or potential subsidence in oil and gas producing areas has prompted development of remedial operations and techniques to control and relieve the resultant well problems.

We shall introduce here a new approach developed for combating subsidence problems in producing wells in the Houston-Galveston area of the Texas Gulf Coast. The advantages of this new solution have been substantiated by field tests.

Subsidence in the Houston-Galveston Area

Land subsidence has been recognized in the Houston-Galveston area for quite some time.1,2 Beginning in 1905–1906 the U. S. Coast and Geodetic Survey established nets of first- and second-order level lines covering the area. Major releveling surveys conducted in 1942–1943, 1953–1954 and 1964 have been used to develop maps of generalized surface subsidence (Fig. 1).4,5 Ground settlement has been continuous since it was originally identified. By 1964 maximum total subsidence had reached 5 to 6 ft. The area within which subsidence was 1 ft or more had increased from an 8-×18-mile oval shape of the 1906–1943 surveys to more than 40 miles in diameter with an additional extension to the southeast that included the Texas City vicinity.

Subsidence Problems in Oil Producing Operations

Humble has experienced subsidence problems in Houston-Galveston area fields involving approximately 500 total oil and gas wells. Other operators have also recognized these problems and have been active in repairing them. To understand the problem and forces involved, consider a line diagram of a typical well (Fig. 2). Many of the wells in this area were drilled 25 to 30 years ago. The surface pipe, consisting of 1,000 to 1,500 it of 9 5/8-in. casing, was cemented throughout the entire length while the pipe was in tension. The production string, consisting of 6,000 ft of 5 1/2-in. casing, was landed in tension with the bottom 1,000 ft cemented. When the production string was landed in the casinghead, the upper portion of the surface casing was placed in compressive loading. Under normal conditions there should be no appreciable change with time in the forces involved. However, when the wells have been re-entered it has been found that the forces originally in the casing strings have been reversed. The surface casing at the top of the ground is in tension, whereas the oil string is in compression. There has been no detectable movement of the casinghead relative to the ground surface.
Well-Test Model Identification With Self-Organizing Feature Map
Authors: Sinha Sandeep , Panda M. N.
Published: December 2007

Well-test data have been used traditionally for determining a variety of reservoir parameters, such as average permeability, storage capacity, reservoir damage, presence of faults and fractures, and reservoir mechanism. A number of techniques, both conventional methods, such as type-curve matching and numerical simulation, and artificial intelligence (AI) methods, have been used for identifying well-test models. These methods are laborious and time-consuming and at times give incorrect results.

Artificial neural networks (ANN's) are recent developments in computer vision and image analysis. These networks are specialized computer software that generate a strategy to produce nonlinear mapping functions for complex problems. ANN's are commonly used as a tool for recognizing an object or predicting an event given an associated pattern. Only a limited number of applications of ANN for analyzing well-test data have been reported. These applications are mostly model-specific (developed for specific reservoir models) and, hence, are not general enough.

This paper presents a new method based on ANN's that uses Ko-honen's self-organizing feature (SOF) mapping technique to identify well-test interpretation models. By grouping well-test data into distinct categories, the SOF algorithm produces a general mapping function. This method can help analyze well-test data from a large variety of reservoirs (including reservoirs with faults, fractures, boundaries, etc.) more efficiently and inexpensively than was feasible previously.
Parachors Based on Modern Physics and Their Uses in IFT Prediction of Reservoir Fluids
Authors: Schechter D. S. , Guo Boyun
Published: December 2007

Prediction of interfacial tension (IFT) is essential for modeling many secondary and tertiary oil recovery processes. The parachor method (PM) has been widely used to predict IFT. There has been considerable confusion in the literature concerning the PM for estimating IFT. The confusion is based primarily on the lack of clarity concerning the scaling exponent and parachors derived from this exponent.

According to modern physics, the theoretical value ofthe scaling exponent is 3.88 for all pure substances, although several values may be found in the literature, usually altered to match existing data. This paper addresses clarification of the confusion about the scaling exponent, derivation of parachors for pure species occurring in petroleum fluids and oil cuts, and verification of the validity of these derived parachors in IFT prediction of reservoir fluids.

We have analyzed experimental data for various compounds occurring in reservoir fluids and found that 3.88 is a valid scaling exponent for pure species inside and outside, to some large extension, of the critical region. Taking 3.88 as a fixed scaling exponent, parachors of 139 crude oil components are back-calculated by means of surface tension and density data obtained from experiments by previous investigators. These parachors are compared with three selected parachor correlations for IFT prediction of six crude oil and CO2 mixtures and are found to be more accurate.
Miscible Gas Displacement of Multicomponent Oils
Authors: Johns R. T. , Orr F. M.
Published: December 2007

This paper extends the theory of multicontact miscible displacements in four-component systems to displacements by a single gas component of an oil containing any number of components. Multicomponent solutions are developed using the method of characteristics in the absence of dispersion and are shown to consist of a series of successive pseudoternary displacements. Example analytical solutions are constructed and compared to experimental results for a synthetic ten-component oil displaced by CO2 as given by Metcalfe and Yarborough1.

The minimum pressure for miscibility (MMP) for the synthetic oil is determined to be substantially below pressures used in the experiments and is below the bubble-point pressure. We show that multicontact miscibility (MCM) can be achieved even when an oil exists as two phases. The displacement of the synthetic oil by CO2 is demonstrated to have features of both condensing and vaporizing mechanisms (C/V). Furthermore, the key tie line that controls development of miscibility is the crossover tie line that divides the condensing and vaporizing portions of the displacement path (composition route).

Extension of the theory for displacements of real oils with an arbitrary number of components is also discussed. For displacements by CO2 of an oil that contains only methane (CH4), ethane (C2) and heavier components, we demonstrate that the most downstream crossover tie line will control the development of miscibility. For displacements by the most volatile component (i.e. pure N2 or CH4 injection) of the same oil, however, displacements are purely vaporizing and miscibility is controlled by the tie line that extends through the oil. A comparison of the component volatilities of the oil relative to the injection gas determines which one of the tie lines will control the development of miscibility. A procedure is given that can be used to find the key tie line that controls miscibility and also to estimate the MMP from an equation-of-state (EOS).
Thermal Stresses Around a Wellbore and Their Small Effect on Velocity Logging
Authors: Tuman V.S.
Published: December 2007

TUMAN, V.S., MEMBER AIME, U. OF ILLINOIS, URBANA, ILL.

In the first part of this paper, an estimate is made of the magnitude and extent of the thermal stresses which result from mud circulation. Our study is made for the period of relaxation, i.e., when the drilling operations are terminated and mud circulation is discontinued. In the second part, we have shown how the thermal stress can affect the wave propagation. An example is worked out for a Carbondale sandstone (Illinois basin). It is concluded that, in extreme cases when differential temperature is about 100 degrees F, the travel time will be affected by about 2 microsec/ft. For more refined permeability studies, such corrections would be desirable.

MAGNITUDE AND EXTENT OF THERMAL STRESSES RESULTING FROM MUD CIRCULATION

When geological beds are penetrated by boreholes, it is observed that the formation temperatures increase with depth; however, the temperature profile varies considerably from place to place. During drilling operations, mud pumped from a pit at atmospheric temperature absorbs heat from the lower beds. As a result, the drilling fluid returning to the surface is at a higher temperature than the surrounding beds. The temperature gradient in a well depends on the rate of mud circulation and other factors; normally, this temperature gradient is smaller than the natural gradient in the formations. (See Fig. 1.)The temperature difference between the mud column and the surrounding beds gives rise to thermal stresses (which are also important in the phenomenon of fracturing), and it is expected that they will affect the transit time of the sonic front in velocity logging. It is evident that beds near the surface will undergo various cycles and will have a complicated dynamical and thermal-stress history. A limestone bed which is just penetrated will act as a source of heat, warming up the cold mud pumped down a few minutes earlier from the surface pit. The same limestone bed a week later will act as a sink, absorbing heat from the drilling mud which has already warmed up sufficiently to be at a higher temperature than the bed in question. No doubt a large section of the hole will undergo a heat treatment, which will make the calculation of the exact magnitude of the thermal stresses very difficult. In the solution of wellbore thermal equation, it is assumed that the rock around the wellbore is elastic and isotropic, and that the system is radially symmetrical. A complete dynamical solution of the thermal stresses set up at different horizons during the drilling operations would require a comprehensive history of the mud circulation, the surface temperature of the pit and the number of hours in which mud was not circulated.

SPEJ

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Alternative Stimulation Fluids and Their Impact on Carbonate Acidizing
Authors: Fredd C. N. , Fogler H. Scott
Published: December 2007

Acidizing treatments are commonly used to remove near-wellbore damage and create artificial flow channels in carbonate formations. Matrix acidizing treatments are most useful when fracture acidizing is undesirable, such as when a shale break or other natural boundary must be maintained to prevent water or gas production1 or where fracture acidizing is ineffective, such as in soft chalk formations.2 Unfortunately, matrix treatments often require low injection rates to prevent fracturing the formation rock. These treatments may also be required in heterogeneous formations with zones of low conductivity (which need stimulation the most) that accept acid at low rates. It is at these low injection rates that the problem of rapid acid spending severely limits the acid penetration distance. The injection of hydrochloric acid (HCl) into carbonate formations at low rates results in face dissolution, or complete dissolution of the carbonate matrix near the wellbore. This face dissolution consumes large volumes of acid and provides negligible increases in the conductivity of the formation.

Various acid systems have been used to reduce the limitations of rapid acid spending at low injection rates. A few of the acids include: weak acids, such as acetic and formic acid, which have relatively low H+ concentrations and therefore react with carbonates at a slower rate than HCl3,4; chemically retarded acids, such as oil external microemulsion systems containing HCl, that retard acid diffusion to the carbonate surface and thus allow deeper penetration of live acid2; and foamed acids (nitrogen gas and aqueous HCl) that prevent acid from spending outside the primary dissolution channel, thereby promoting the growth of wormholes.5

Although retarded and foamed acid systems can stimulate carbonate formations at lower injection rates, strong acids such as HCl induce the precipitation of asphaltic sludge from crude oil. This sludge can plug the formation and restrict production after an acidizing treatment. When ferric ions are present, this problem is even more severe.6 Thus, adequate corrosion protection becomes more essential. Acetic acid (HAc), an iron chelating agent, does not reduce sludging tendencies in the presence of ferric and ferrous iron.6 A variety of acid additives (antisludging agents, corrosion inhibitors, and iron-reducing agents) have been used to prevent the sludging problem. However, their effectiveness is limited by the need to obtain a compatible combination of additives and a lack of understanding of the complex chemistries involved in the precipitation reactions. These limitations demonstrate the need for an alternative stimulation fluid that combines the ability to stimulate at low injection rates with fluid properties that are not conducive to asphaltic sludge precipitation or corrosion problems.
A Ten-Pound Cement Slurry for Oil Wells
Authors: Coffer Henry F. , Reynolds J.J. , Clark Roscoe C.
Published: December 2007

A cement slurry lightweight additive has been adapted in the Conoco laboratories for use in oil well cements. This additive makes possible the use of air to lighten oil well cement slurries. Specifically, the additive consists of small clay bubbles of air having sufficient strength to resist crushing by bottom hole pressures. Clay bubble cement slurry weights can be safely reduced to 10 lbs/gal. In addition, the clay bubbles tend to act as lost circulation materials and to provide a cement texture which should produce good perforating characteristics. Clay bubble cement is relatively impermeable.

Introduction

In many areas in Oklahoma, Texas, Wyoming, and California, difficulties are experienced during casing cementing operations with lost returns caused by the high density of the cement slurries. Wells in these areas are ordinarily drilled with 9 to 11 lbs/gal. drilling mud while neat cement slurries may range in densities from 14.5 to 17 lbs/gal. In these areas, cement slurry weights are at present being successfully reduced to around 12 lbs/gal. (under bottom-hole conditions) by the use of additives in the cement. Since the use of additives will decrease the strength which the cement will develop, the amount of additives which can be used must be based on the minimum cement strength which is acceptable; and thus the maximum slurry weight can be reduced. At present, the minimum tensile strength generally acceptable is 50 lbs/sq in. cured for 24 hours under bottom-hole temperature. This figure is based on laboratory tests and on a large number of cement jobs which have been conducted using cement which will not develop more than 50 psi tensile strength in 24 hours under bottom-hole conditions.
Interfacial Tension of the Methane-Normal Heptane System
Authors: Warren H.G. , Hough E.W.
Published: December 2007

The interfacial tension values for the methane-n heptane two-phase system were determined by the pendeant-drop method on eight isotherms from 100 degrees pendeant-drop method on eight isotherms from 100 degrees to 310 degrees F. The pressure range was from 215 to 3,415 psia. Direct measurements of the maximum and minimum drop diameters were made. The tables of Winkel and the density difference data of Reamer et al. were used to calculate experimental values of interfacial tension. The experimental data varied from 16.64 dynes/cm at 217 psia at 100 degrees F to 0.081 dynes/cm at 3,415 psia at 130 degrees F. The smooth data is given in Table 1. Fig. 1 is a plot of smoothed data at 0.1, 1.0, 5.0 and 10.0 dynes/cm over the range of 100 degrees to 310 degrees F and 0 to 3,618 psia. The dashed lines are extrapolation of the data. A correlation of these data along with other hydrocarbon systems has been published. The data are taken from the PhD dissertation of one of the authors.

The supplement of the American Chemical Society Research Fund Grant No. 635-A is gratefully acknowledged.

TABLE 1 - INTERFACIAL TENSION OF THE METHANE - NORMAL HEPTANE SYSTEM SMOOTHED DATA

Interfacial Tension (dynes/cm) Pressure Pressure psia 100 F 130 F 160F 190 F 220 F 250 F 280 F 310 F psia 100 F 130 F 160F 190 F 220 F 250 F 280 F 310 F

400 14.88 13.75 12.50 11.28 9.97 8.83 7.74 6.60800 11.33 10.60 9.88 8.96 7.96 6.98 6.07 5.111,200 8.50 8.00 7.55 6.88 6.18 5.32 4.55 3.711,600 6.16 5.85 5.53 5.04 4.54 3.80 3.16 2.482,000 4.21 4.06 3.83 3.47 3.04 0.45 1.90 1.352,200 3.35 3.83 3.47 3.04 2.37 1.85 1.39 0.872,400 2.57 2.50 2.36 2.13 1.76 1.30 0.91 0.472,600 1.85 1.82 1.73 1.54 1.23 0.83 0.50 0.132,800 1.22 1.22 1.15 1.00 0.74 0.41 0.17 2709*3,000 0.73 0.73 0.67 0.56 0.34 0.13 2927*3,100 0.53 0.53 0.47 0.37 0.19 0.033,200 0.35 0.35 0.31 0.23 0.07 3122*3,300 0.22 0.22 0.19 0.12 3298*3,400 0.13 0.13 0.10 0.033,500 0.06 0.02 3549*3,600 3606* 3618*

*Critical pressure at temperature.

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Hoop-Stress Loading - A New Method of Determining the Tensile Strength of Rock
Authors: Hardy H. Reginald , Jayaraman Natesa I.
Published: December 2007

Although it is well known that rock commonly fails in tension under numerous field conditions, a satisfactory standard procedure for determination of the tensile strength of such materials has not as yet been established. With suitable precautions, direct-pull tests may be used; however, precise specimen preparation and extremely uniform and concentric loading must be utilized if meaningful results are to be obtained using this method. Recently, the authors completed a 3-year study in which a variety of methods for determining tensile strength were evaluated. One method, involving the hoop-stress loading of thick-walled hollow cylinders, was found to be particularly attractive. This paper describes the theory, apparatus, and test technique associated with this method.

In evaluating this new technique a number of specimens of Barre granite, Lauders and Indiana limestone, and Berea and Tennessee sandstone were tested. Reproducibility for each rock type was fund to be excellent, with the percentage standard deviation ranging from a maximum of 10.9 percent for Lauders limestone down to 0.9 percent for Berea sandstone. Values of tensile strength determined from hoop-stress tests were found to correspond closely to those determined by direct pull, provided the former were analyzed in terms of pull, provided the former were analyzed in terms of an equation based on a suitable elastic-plastic analysis. Under these conditions the ratio of hoop-stress to direct-pull tensile strength values ranged from 0.86 to 1.10 for the five rocks tested. Although studies on additional rock types are required, it appears that the hoop-stress loading method would be a strong candidate as a standard test for determination of the tensile strength of rock.

Introduction

Although it is well known that tensile stresses play an important role in the behavior of underground play an important role in the behavior of underground openings associated with petroleum, natural gas and mining operations, suitable techniques for the determination of the tensile strength of rock are limited.
Comparison of Methods for Analyzing a Water Drive Field, Torchlight Ten Sleep Reservoir, Wyoming
Authors: Stewart F.M. , Callaway F.H. , Gladfelter R.E.
Published: December 2007

In this paper oil initially in place is calculated by the various methods commonly used for analysis of water drive fields using data available as time progresses. Rate and pressure are predicted by means of the same methods using data available at the end of two years' history. These predictions are then compared with subsequent performance permitting an evaluation of the methods, which are Modified Schilthuis, Simplified Hurst, van Everdingen et al (1952), and the Electric Analyzer.

Introduction

Several variations of the material balance equation, differing in the term used to evaluate water influx, are in common use for estimating oil in place, predicting rate and volume of water influx, and forecasting producing rates and reservoir pressure in water drive reservoirs. The electric analyzer with an electrical network set up to simulate the oil reservoir and aquifer and their contained fluids may be used for the same purpose.

Examples of the application of one or another of these methods have appeared in the literature. The accuracy and reliability of the material balance for calculating oil in place have been covered. However, there have been few articles in which more than one method has been applied to an actual field allowing a comparison. It is felt that a field example, simple in nature, where the Modified Schilthuis, Simplified Hurst, van Everdingen et al (1952), and the Electric Analyzer have been applied would be of benefit in providing an evaluation of these methods as to their comparative usefulness and reliability in calculating initial oil in place and predicting performance.
Hindcasting Hurricane Waves in the Gulf of Mexico
Authors: Patterson M. M.
Published: December 2007

An estimate of wave heights is needed for risk and venture analysis, for platform design, and for operational planning. Very little reliable data on hurricane waves have been available for a number of years. The present hindcast system uses a moving, two-dimensional wind field to generates and propagate waves to a location of interest. The propagate waves to a location of interest. The wind-wave model is based on work reported in the literature by Wilson. Wave Program I uses a synoptic wind field based on measurements or observations. Wave Program II generates its own wind field based on the track, the time history of the radius to maximum Winds, and the barometric pressure of the storm. Wave Program III also pressure of the storm. Wave Program III also generates its own wind fields, but the storm is moved along a predetermined path. The results of all three hindcast methods have been compared with data gathered from Hurricane Carla. Other hurricanes have also been studied and each of the programs gives comparable results.

Introduction

The most critical environmental factor in deepwater platform design is the selection of wave heights to which the platform will be subjected. Regardless of the design theory, wave loading contributes a major portion of the environmental force on a deep-water platform. To date there has been little sound historical evidence of the magnitude of wave heights that could occur in the Gulf of Mexico. To overcome this problem the offshore oil industry has sought an answer by two related methods. The first method consists of several measuring programs to gather both wave force and wave height information. Since reliable measuring techniques have existed for only a short time, the second method consists of developing techniques to predict historical waves that probably occurred in the Gulf of Mexico. The purpose of this paper is to document Shell's efforts in hindcasting paper is to document Shell's efforts in hindcasting waves for hurricanes that have passed through the Gulf since 1900. In order to hindcast waves, it was necessary to find a mathematical simulation model that would generate waves from a moving wind field. Such wind fields may be taken from synoptic charts or developed from empirical equations based on hurricane data such as radius to maximum winds, central pressure, and forward speed.
A Study of Suction and Scouring of Bottom-Sitting Offshore Structures
Authors: Ninomiya Katsuya , Tagaya Kozo , Murase Yoshihide
Published: December 2007

Two sources of difficulty with offshore submersible structures are suction and scour. It seems reasonable to suppose that the shape of the structure will influence the effect of these forces and the degree of damage they will inflict. Suction-breaker and scour tests have been conducted on models of five different shapes, and the results are presented here.

Introduction

When a submersible offshore structure sits on the soft, cohesive soil of the sea bed, it penetrates deeply into the soil. When the structure is freed from the bottom, a great suction force is created that not only makes the freeing operation difficult, but also can wreck or capsize the structure.

If the foundation soil is sandy, tidal currents or waves may cause scour around the legs of the structure, causing it to turn over, or may cause great local stress upon the structural members. The purposes of this investigation were to study the characteristics of suction and scouring, to develop an efficient suction breaker, and to examine a preventive method against scouring. Suction and scouring were investigated in an experimental tank, and the practical application of the suction breaker was field tested using a large model in the sea.

Laboratory Suction-Breaker Test Models and Testing Soil

To study the characteristics of suction and the effectiveness of a suction breaker, we designed and manufactured five types of small models (Fig. 1) made of steel and coated with paint, and having a bottom area of 219 sq ft.

Sea silt taken from the bed of Hiroshima Bay was reconsolidated and used as the testing soil. First the silt was agitated with water in a holding tank. Then a sheet of canvas was laid over the surface of the silt, and it was weighted down by perforated steel plates for 1 week. The pressure was approximately plates for 1 week. The pressure was approximately 1.5 psi. According to a Vane shear test, the mean cohesion of this soil was as follows.

Cohesion of the soil applied to the suction test:

C = 0.56 psi.

Cohesion of soil applied to the suction-breaker test:

C = 0.53 pk

Method of Testing

Suction Test. After the model penetrated the soil about 8 in. by means of loading, it was unloaded and leg alone for about 5 minutes. Then it was pulled up at a rate of 0.08 in./min; the pulling pulled up at a rate of 0.08 in./min; the pulling force was continuously measured by a tension meter the displacement gauge was read by a displacement gauge every 5 seconds.

Suction-Breaker Test. After the model had been sunk into the soil by means of loading as shown in Fig. 2, it was pulled up. When it had been pulled up about 0.8 in. (that is, when the contact pressure under the weight of the model was about zero), pressurized water was jetted by the pumping of the suction breaker until the model was completely pulled out. Items measured were the pulling force, the displacement, the pressure, and the flow rate of the pump.

JPT

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