bluuebunny/crossref_metadata_2025 huggingface dataset:
Spontaneous Ignition in Oil Reservoirs
Authors: Burger Jacques G.
Published: December 2007

Typical experimental data on low-temperature oil oxidation in porous media are presented. Using these kinetic data, numerical models in radial and longitudinal flow are proposed for computing the spontaneous ignition conditions when air is injected into oil reservoirs. The models account for heat transport by conduction and convection in the formation.

The computed ignition times are compared with the values obtained by an analytical approach. The distance from the well to the injection zone is also discussed.

Introduction

Ignition is the first step of the in-situ combustion process. It may be obtained by heating the formation around the ignition well with a burner or an electrical heater.

The heat required to initiate a combustion front also may be provided by an exothermic reaction between air and an appropriate chemical compound. This compound may be an easily oxidizable organic liquid injected into the formation in the vicinity of the ignition well before air injection. But if the formation crude oil itself has sufficient reactivity with oxygen under reservoir conditions, the formation may ignite spontaneously when air is injected for a prolonged period. As a matter of fact, spontaneous prolonged period. As a matter of fact, spontaneous ignition has been obtained in some reservoirs in a reasonably short time.

The ignition delay may vary from a few days to an indefinite period if the rate of heat dissipation to the surroundings of the reacting volume prematurely becomes as high as the rate of heat prematurely becomes as high as the rate of heat release.

In the approximate analytical approach of Tadema and Weijdema, heat dissipation by conduction and convection was neglected. Hence, ignition would occur for all reservoir conditions eventually after an ignition delay of several years. However, if Tadema and Weijdema's approach gives a good approximation of the ignition delay when the oxidation rate is high under reservoir conditions, this delay is likely to be significantly underestimated when crude oil reactivity is low.

A numerical model was built for computing the ignition conditions (ignition delay and position of the ignition zone) as a function of reservoir, oil, and gas flow characteristics. The kinetic parameters of oil oxidation were determined experimentally.

DESCRIPTION OF THE NUMERICAL MODEL

Gas flow is assumed to be one dimensional and linear in x or radial in r. Longitudinal conduction and convection are accounted for. Transversal conduction is neglected since, during the ignition delay, the vertical temperature gradient is very low, especially if the central part of the oil layer is considered. Fluid and solid temperatures are supposed to be equal.

Air is injected into the ignition well. Pressure and gas flow rate are assumed to be approximately constant in the investigated zone around the well. Water and oil flow or vaporization are neglected in the heat balance. Diffusion-dispersion of oxygen is not considered.

SPEJ

P. 73
High Penetration Rates and Extended Bit Life Through Revolutionary Hydraulic and Mechanical Design in PDC Drill Bit Development
Authors: Taylor M. R. , Murdock A. D. , Evans S. M.
Published: December 2007

PDC drill bit developments have been made to achieve higher penetration rates and longer life, involving a compromise between open, light set, bits for speed, and heavy set ones for durability. Developments are described which provided the benefits of both in a revolutionary hydraulic and mechanical design. The hydraulic design causes mud to flow first towards the bit center and then outwards. It was extensively flow tested using high-speed photography to ensure that bit balling was prevented. It includes features to address bit whirl which were demonstrated in full scale laboratory testing to reduce the bit's vibration level. The mechanical design maximizes open-face volume, known to benefit penetration rate, by using very high blades. However, the heights attainable can be limited by the bit body's mechanical strength. Steel was chosen to maximize blade strength and was coated with a newly developed hardfacing to improve erosion resistance. A program of fatigue testing assured adequate strength.
How to Improve Rate of Penetration in Field Operations
Authors: Fear M. J.
Published: December 2007

A method has been developed to identify which factors are controlling rate of penetration (ROP) in a particular group of bit runs. The method uses foot-based mud logging data, geological information, and drill bit characteristics, to produce numerical correlations between ROP and applied drilling parameters or other attributes of drilling conditions. These correlations are then used to generate recommendations for maximizing ROP in drilling operations.
New Formulations of Potassium Acetate and Potassium Formate Polymer Muds Greatly Improved Drilling and Waste Disposal Operations in South Italy
Authors: Gallino G. , Guarneri A. , Maglione R. , Nunzi P. , Xiao L.
Published: December 2007

This paper discusses the field results of innovative K-Acetate or K-Formate mud formulations that have been used by ENI S.p.A./Agip Division to drill several wells through very plastic shales in South Italy. Field muds have been carefully designed and evaluated as far as drilling and waste disposal activities are concerned. While drilling, the integration between field observations, standard laboratory tests, and nonconventional rheological approaches provided the assessment of useful correlations between rheological properties, performance, and formulations of field muds. These findings permitted a gradual improvement of the mud effectiveness with a large reduction in dilution rates, bit balling, and hole cleaning problems. At the rig, the strict cooperation between all the people involved in field operations represented a key factor for the successful application of the know-how acquired. With respect to the previous wells drilled in the field with traditional dispersed muds, the optimization and careful management of the new muds contributed, in spite of the increased ROP, to a considerable reduction both in time spent to remove bit balling or reaming and in tons of wastes produced per hole volume. These improvements led to great savings in drilling and disposal costs that largely compensated the 8.4% increase in the mud mixing costs per hole volume due to the presence of potassium salts.
A Material for Tubing and Casing Applications in Deep, Sour Gas Wells
Authors: Heacox Richard A. , Stroup James P.
Published: December 2007

Introduction

Multiphase MP35N is a nickel-cobalt-base alloy containing 35-percent nickel, 35-percent cobalt, 20-percent chromium, and 10-percent molybdenum that is produced by double vacuum melting. MP35N exhibits a produced by double vacuum melting. MP35N exhibits a unique combination of ultrahigh strengths, good ductility, and excellent corrosion resistance.

Multiphase MP35N develops yield strengths of 150 to 250 ksi with 10- to 25-percent elongation by cold working and aging. Mechanical property data for large bars and tubing are presented. Corrosion test results show excellent resistance to cracking in H2S environments. Testing by a number of oil companies has resulted in very high interest in this alloy for such applications as down-hole tubing and casing in deep, sour well environments and for valve cores exposed to H2S. Presently, this alloy is being used successfully for Presently, this alloy is being used successfully for cables to suspend instrument packages in sour wells.

Metallurgy

At high temperatures MP35N has an austenitic face-centered cubic (FCC) structure. Although a hexagonal close-packed (HCP) structure is stable below about 800 deg. F, this transformation is so sluggish that the FCC structure remains after cooling to room temperature. Subsequent cold working results in the formation of thin, coherent HCP platelets in the metastable FCC matrix. The coherency of the platelets strains the lattice and results in strengthening. The amount of strengthening (transformation) depends on the amount and, to a lesser degree, the temperature of deformation. Further strengthening can be achieved by aging, which results in precipitation of a Co3Mo compound at the interfaces between the FCC matrix and the HCP platelets.

In the annealed condition (Table 1) MP35N exhibits moderate strengths and very high ductilities. The effect of cold reduction (by drawing) and aging on the room-temperature tensile properties of MP35N is shown in Fig. 1. For fastener applications (bar sizes of 0.2 to 1.3 in.), cold reduction is designed to provide an ultimate minimum tensile strength of 260 ksi, a 0.2-percent minimum yield strength of 240 ksi, and ductility minimums of 8-percent elongation and 35-percent reduction of area after aging at 1,100 deg. F. Note also that the properties of MP35N can be controlled over a wide range by adjusting the amount of cold reduction.

Properties obtained from large-diameter bars are shown in Table 2. The two larger bars were produced by cold Pilgering rather than by cold drawing. Note that, after equivalent amounts of cold work, the material reduced by drawing exhibits higher strengths than the Pilgered material.

TABLE 1 -- TYPICAL ANNEALED PROPERTIES OF MP35N

Tensile strength, ksi 135 0.2-percent yield strength, ksi 60 Elongation in four dimensions, percent 70 Reduction of area, percent 70 Hardness 90 to 100 Rb Charpy V-notch impact, ft lb 2,001

JPT

P. 705
New Apparatus for Studying Pressure Induced Fracturing in Reference to Lost Circulation
Authors: Teplitz A.J. , Pohoriles E.M. , Rodgers J.K.
Published: December 2007

Introduction

This note is presented in order to call attention to a newly developed laboratory apparatus that appears to have interesting possibilities for the study of lost circulation of the pressure-parting type, for a more realistic evaluation of sealing materials for this type of loss, and for investigation of other aspects of hydraulic fracturing.

A study of lost circulation, conducted jointly by operating divisions of the Gulf Oil Corp. and the Gulf Research & Development Co., has been in progress for the past few years. Earlier phases of the study dealt with mechanical factors contributing to loss of returns in laminar type sediments.

One aspect of this type of loss which has been widely discussed in the literature and elsewhere concerns the geometry of the fractures into which such losses occur. This subject is not merely a philosophical one, but has an important bearing on procedures for combating lost circulation difficulties and on other well operations.

The further course of the collaborative studies previously mentioned has produced some information on this subject which, though limited in amount, is believed to be significant. In several typical cases of lost circulation in laminated shale and sand formations, the wells have been surveyed with instruments capable of detecting the points of loss with considerable accuracy. These wells were located in the Gulf Coast of Texas and Louisiana, in the Texas Panhandle, and in the Rocky Mountain area. In each of these instances the loss was shown to be occurring at some distance removed from the bottom of the hole and sharply confined to a very narrow interval, less than 1 ft in thickness.

It is rather difficult to imagine that fractures of a vertical nature would be of the limited extent indicated by the surveys in these wells. Furthermore, the high rates of loss at relatively low pressure differentials observed in some of these instances together with the narrow intervals involved would appear to require the radial flow pattern which would be associated with a more or less horizontal fracture plane.
The Energy Yield of Micellar Flooding
Authors: Carpenter Dan H. , Davies John B.
Published: December 2007

JPT Forum articles are limited to 1,500 words including 250 words for each table and figure, or a maximum of two pages in JPT. A Forum article may present preliminary results or conclusions of an investigation that the present preliminary results or conclusions of an investigation that the author wishes to publish before completing a full study; it may impart general technical information that does not warrant publication as a full-length paper. All Forum articles are subject to approval by an editorial committee.

Letters to the editor are published under Dialogue, and may cover technical or nontechnical topics. SPE-AIME reserves the right to edit letters for style and content.

Introduction

The higher price of crude oil and the dependence on crude imports are providing a great incentive to accelerate commercialization of enhanced oil recovery procedures. Recovery of known oil in place is becoming an procedures. Recovery of known oil in place is becoming an increasingly urgent matter for the petroleum industry because, for enhanced recovery to be economically attractive, it must be initiated before producing fields are shut down and existing wells are plugged. Unfortunately, however, the present political uncertainty about future oil prices causes companies to be reluctant to make the large front-end investments in chemicals and chemical manufacturing plants that are necessary to demonstrate enhanced recovery technology on a large scale.

The U.S. crude oil "barrel" (Fig. 11) shows a target of about 60 billion bbl of additional oil physically recoverable with enhanced recovery methods now being developed. In addition, some 60 billion bbl may be recovered with future enhanced recovery methods. There are four principal enhanced oil recovery techniques now considered feasible for the production of crude oil: thermal recovery methods, hydrocarbon miscible floods, carbon dioxide floods, and water-miscible micellar floods.

All methods require introducing energy into oil-bearing formations by gas, water, or solvents under pressure, but each technique has its own advantages and pressure, but each technique has its own advantages and limitations.

Thermal recovery methods are perhaps uniquely suited to recovering viscous crudes, but they also may be used to recover many conventional crudes. This is not, however, a broadly applicable technique because of the required formation porosity and the lack of sweep control. Hydrocarbon miscible flooding probably can be discounted as a widespread commercial recovery method because of the general unavailability of low-cost ethane and propane. Limitations on control for the flood bank and pressure requirements to achieve miscibility create practical problems that will limit commercialization of this technique. Carbon dioxide miscible floods suffer from a lack of cheap carbon dioxide in areas near many potential project sites, and from the same general limitations and problems of hydrocarbon miscible systems.

JPT

P. 103
Improved Model for Collapse Pressure of Oval Coiled Tubing
Authors: Zheng A. S.
Published: December 2007

This paper presents a new modeling technique to predict collapse pressure of oval coiled tubing. Through finite element analysis, a failure mechanism for tubing collapse is identified and a collapse model proposed. This model relates the tubing collapse pressure with its yield strength, ovality and its D/t ratio. Collapse pressures predicted by this model correlates well with finite element method prediction. Collapse experiments were also performed to generate test data for collapse pressure under various ovality. To better simulate the actual material behavior in a typical tubing operation, the ovality in the collapse experiments was generated through a fatigue machine. Predictions from this model are compared against the experimental data as well as other published test data and good agreement is achieved. This new model predicts very well the effect of the ovality and axial force on the collapse pressure. The paper concludes with an introduction to an enhanced software that incorporates this new modeling technique for collapse prediction.
Improved Prediction of Reservoir Behavior Through Integration of Quantitative Geological and Petrophysical Data
Authors: Davies D. K. , Vessell R. K. , Auman J. B.
Published: December 2007

This paper presents a cost effective, quantitative methodology for reservoir characterization that results in improved prediction of permeability, production and injection behavior during primary and enhanced recovery operations. The method is based fundamentally on the identification of rock types (intervals of rock with unique pore geometry). This approach uses image analysis of core material to quantitatively identify various pore geometries. When combined with more traditional petrophysical measurements, such as porosity, permeability and capillary pressure, intervals of rock with various pore geometries (rock types) can be recognized from conventional wireline logs in noncored wells or intervals. This allows for calculation of rock type and improved estimation of permeability and saturation. Based on geological input, the reservoirs can then be divided into flow units (hydrodynamically continuous layers) and grid blocks for simulation. Results are presented of detailed studies in two, distinctly different, complex reservoirs: a low porosity carbonate reservoir and a high porosity sandstone reservoir. When combined with production data, the improved characterization and predictability of performance obtained using this unique technique have provided a means of targeting the highest quality development drilling locations, improving pattern design, rapidly recognizing conformance and formation damage problems, identifying bypassed pay intervals, and improving assessments of present and future value.
Determination of Producible Hydrocarbon Type and Oil Quality in Wells Drilled With Synthetic Oil-Based Muds
Authors: Hashem M. N. , Thomas E. C. , McNeil R. I. , Mullins Oliver
Published: December 2007

Determination of the type and quality of hydrocarbon fluid that can be produced from a formation prior to construction of production facilities is of equal economic importance to predicting the fluid rate and flowing pressure. We have become adept at making such estimates for formations drilled with water-based muds, using open-hole formation evaluation procedures. However, these standard open-hole methods are somewhat handicapped in wells drilled with synthetic oil-based mud because of the chemical and physical similarity between the synthetic oil-based filtrate and any producible oil that may be present. Also complicating the prediction is that in situ hydrocarbons will be miscibly displaced away from the wellbore by the invading oil-based mud filtrate, leaving little or no trace of the original hydrocarbon in the invaded zone. Thus, normal methods that sample fluids in the invaded zone will be of little use in predicting the in situ type and quality of hydrocarbons deeper in the formation. Only when we can pump significant volume of filtrate from the invaded zone to reconnect and sample the virgin fluids are we successful. However, since the in situ oil and filtrate are miscible, diffusion mixes the materials and blurs the interface; as mud filtrate is pumped from the formation into the borehole, the degree of contamination is greater than one might expect, and it is difficult to know when to stop pumping and start sampling. What level of filtrate contamination in the in situ fluid is tolerable?

We propose a procedure for enhancing the value of the data derived from a particular open-hole wireline formation tester by quantitatively evaluating in real time the quality of the fluid being collected. The approach focuses on expanding the display of the spectroscopic data as a function of time on a more sensitive scale than has been used previously. This enhanced sensitivity allows one to confidently decide when in the pumping cycle to begin the sampling procedure. The study also utilizes laboratory determined PVT information on collected samples to form a data set that we use to correlate to the wireline derived spectroscopic data. The accuracy of these correlations has been verified with subsequent predictions and corroborated with laboratory measurements. Lastly, we provide a guideline for predicting the pump-out time needed to obtain a fluid sample of a predetermined level of contamination when sampling conditions fall within our range of empirical data.
Foam Flow in Heterogeneous Porous Media: Effect of Cross Flow
Authors: Bertin H. J. , Apaydin O. G. , Castanier L. M. , Kovscek A. R.
Published: December 2007

Previous experimental studies of foam generation and transport were conducted, mainly, in one-dimensional and homogeneous porous media. However, the field situation is primarily heterogeneous and multidimensional. To begin to bridge this gap, we have studied foam formation and propagation in an annularly heterogeneous porous medium. The experimental system was constructed by centering a 0.050 m diam cylindrical Fontainebleau sandstone core inside an 0.089 m acrylic tube and packing clean Ottawa sand in the annular region. The sandstone permeability is roughly 0.1 μm2 while the unconsolidated sand permeability is 6.7 μm2. Experiments with and without cross flow between the two porous media were conducted. To prevent cross flow, the cylindrical face of the sandstone was encased in a heat-shrink Teflon sleeve and the annular region packed with sand as before. Nitrogen is the gas phase and an alpha olefin sulfonate (AOS 1416) in brine is the foamer. The aqueous phase saturation distribution is garnered using X-ray computed tomography (CT).

Results from this study are striking. When the heterogeneous layers are in capillary communication and cross flow is allowed, foam fronts move at identical rates in each porous medium as quantified by the CT-scan images. Desaturation by foam is efficient and typically complete in about 1 PV of gas injection. When cross flow is prohibited, foam partially plugs the high permeability sand and diverts flow into the low permeability sandstone. The foam front moves through the low permeability region faster than in the high permeability region.
Advances in Homopolar Welding of API Line Pipe for Deepwater Applications
Authors: Hudson R. S. , Carnes R. W. , Nichols S. P.
Published: December 2007

The University of Texas at Austin Center for Electromechanics is conducting a research program, funded by six oil companies, two industrial contractors, and two government agencies, to study homopolar welding of line pipe for J-Lay applications. In 1995, the third year of the five year research program, the set of weld parameters, those input variables used to control weld performance and quality, was expanded to include joint geometry, with dramatic improvement in the mechanical properties of two HSLA nominal 3-in. line pipe materials: X60 and X65. These improvements increased the Charpy V-Notch impact toughness properties to near parent metal values, while maintaining acceptable strength. After demonstrating repeatable performance with the new parameters, new research focused on real world effects including tolerancing the parameters and evaluating the effect of poor fit up resulting from misalignment and rough and wavy interfaces. During the final year of the research program, the pipe welding program has scaled up to 12-in. nominal line pipe, a seven-fold increase in the cross-sectional area. The paper will cover the basics of homopolar welding (HPW), weld parameters and modifications, the effects of these changes on real time process data, mechanical properties, weld upset profile, HPW metallurgy, and the studies of real world effects. Results from HPW of 12-in. pipe will also be presented.
Film-Thickness Distribution for Annular Flow in Directional Wells: Horizontal to Vertical
Authors: Paz R. J. , Shoham Ovadia
Published: December 2007

An experimental and theoretical investigation has been carried out on two-phase annular flow in inclined pipes. The study focused on the effect of the inclination angle on the liquid film thickness distribution. A conductance multiprobe instrument was utilized to measure the local liquid film thickness around half of the pipe periphery for inclination angles of 90°, 75°, 60°, and 45° from the horizontal. A simple analytical model has been developed for the prediction of the liquid film thickness at the top and bottom of the pipe. The model is applicable for the entire range of inclination angles, from horizontal to vertical. Good agreement is observed between the prediction of the model and the experimental data collected in this study and from the literature.
A Contemporary Approach to Matrix Acidizing
Authors: Coulter G. R. , Jennings A. R.
Published: December 2007

This paper presents an updated look at the many variables associated with successful matrix acidizing. Damage types and formation characteristics significant when considering formation damage and damage removal are presented. Emphasis is placed on knowledge of formation mineralogy and temperature. The requirement for and the function of the many acid additives are discussed. General information and guidelines for matrix stimulation of carbonates and sandstones are provided.
Fracturing With a High-Viscosity, Cross-Linked GelContinuous Fracturing Technique
Authors: Free D.L. , Thompson J.E.
Published: December 2007

Introduction

Highly viscous fracturing fluids that could be pumped at relatively high rates with acceptable friction pressure were first introduced 18 years ago. This viscous fluids were oil-water dispersions that created some problems because they required special mixing and pumping techniques. The fluids did, however, prove their value by creating wide, deeply penetrating fractures and by carrying high concentrations of propping agents. Since then, other high viscosity fluids have been introduced and their properties and effectiveness reported. Such fluids now properties and effectiveness reported. Such fluids now are used commonly in all areas. Because there is some variation in fluid requirements of different areas and formations, several types of fluids have evolved. All can be classed as viscous fracturing fluids. While these fluids have been used successfully, most have the same primary disadvantage: they must be batched mixed before use. Batch mixing requires that all water gelling agents be premixed in fracturing tanks before pumping. Often this premixed in fracturing tanks before pumping. Often this leads to additional rig-time expense for the operator and additional rig-time expense for the operator and additional equipment time and man hours for the service company. Also, if the procedure is not completed as planned, there can be considerable expense in preparation planned, there can be considerable expense in preparation of fluid that is not used. These expenses can become prohibitively high on large jobs, such as the prohibitively high on large jobs, such as the "massive-fracturing" type treatment. To overcome the disadvantages of batch mixing, specially prepared materials for gelling water have been developed that can be mixed continuously as the fluid is pumped down hole. These materials, first prepared from guar gum polymers, have been in use for 3 years and have proved polymers, have been in use for 3 years and have proved highly successful. More recently, lower residue guar derivatives have been used successfully.

Cross-Linked Guar Gels

Very high viscosities can be achieved by cross-linking the guar gels. However, preparation of cross-linked guar gels at the well location on a large volume basis has been troublesome and time consuming in the past because of the required batch-mixing technique. That is, the guar gelling agent and cross-linker are premixed in the fracturing water. Adjustments of the fluid's pH are often necessary and present problems in achieving a uniform pH in large fracturing tanks. The guar gelling agent hydrates and produces a high-viscosity solution.

JPT

P. 119
Nonisothermal Gravitational Composition Variation in a Large Deep-water Field
Authors: Padua K. G. de Oliveira
Published: December 2007

This paper examines the oil composition distribution of a large deep-water field which the temperature variation, because of the water depth (800 to 2000 m), is in the opposite direction of the Earth's thermal gradient. The main practical objective is to investigate if the oil distribution would suggest fluid connectivity along this 40 km long and 15 km wide oil field. This could significantly impact the appraisal and development phases of the field. The methodology adopted here includes reservoir geochemistry, fitting of a single equation of state, compositional simulation, and thermodynamic equilibrium. The results from reservoir geochemistry indicate a common oil source, different migration pulses, a lateral migration path and some hydrocarbon mixing after filling process. A single equation of state is set to represent the oil behavior for the whole field. The successful matching is achieved by means of splitting the heaviest component and so reducing the molar concentration of the pseudocomponent on a single regression procedure. Compositional simulation runs, representing the secondary migration, suggest spots of gas caused by phase changes. During the filling process, the results show heavier oil in front of the upward flow. During the mixing process, the gravitational segregation seeks to reverse this trend. A new thermodynamic equilibrium model that accounts for the effect of temperature shows an increase of oil segregation with a temperature gradient opposite to the thermal's gradient. The results suggest thermodynamic equilibrium of oils in an area of the reservoir. This may suggest reservoir connectivity. In the area the oils are in thermodynamic equilibrium, fluid composition and properties are extrapolated to different depths while function of their respective temperatures.
Practical Considerations in the Analysis of Gas-Condensate Well Tests
Authors: Raghavan R. , Chu Wei Chun , Jones J. R.
Published: December 2007

Several pressure buildup tests are analyzed with a view to evaluate the potential of the ideas given in the literature. A broad range of tests is examined to demonstrate the characteristics of responses in wells producing below the dew point. Methods to obtain quantitative information that is consistent for different tests are outlined. The specific contributions of this article are as follows. First, in this article we examine field data, second, we look at multiple rates, third, we examine unfractured and fractured wells, fourth, we look at wells that have been produced for a short time and those produced for a long time, fifth, we consider both depletion-type and cycling scenarios, and, sixth we tie pressure data to relative permeability and PVT data. Many of these issues are addressed for the first time.
Selective Conformance Control in Heterogeneous Reservoirs by Use of Unstable, Reactive Displacements
Authors: Thompson K. E. , Kwon Ohseong
Published: December 2007

This paper examines a conformance control technique in which gel is placed into a heterogeneous porous medium by first injecting a high-viscosity uncrosslinked polymer solution and second, a low-viscosity crosslinker. The latter step causes an unstable displacement to occur and allows the crosslinker to flow selectively into high-permeability strata. A visual flow cell was used to test the procedure, and complete fluid diversion was achieved in a dual-zone medium with a 4:1 permeability ratio. In addition, experiments and numerical simulations were used to study fundamental changes in viscous fingering due to the crosslinker-polymer reaction. When the crosslinking reaction is fast enough so that it occurs during injection, the viscous instability becomes somewhat damped, resulting in less distinct fingers and a nearly plug-flow displacement in some cases. The differences are because gelation causes a large pressure gradient to form just behind the displacement front, whereas unreactive fingering is caused by a small pressure gradient within the fingering zone.
In-Situ Polymerization of an Inflatable Composite Sleeve To Reline Damaged Tubing and Shut Off Perforations
Authors: Saltel J. L. , Leighton J. R. N. , Faure A. M. , Baaijens Thijs
Published: December 2007

Finding an effective solution to seal-off perforations, whether it be to reduce gas flow, reduce water cut, or to modify injection profiles, has long been a subject of concern. Several solutions for through tubing shut-off have been tried with a varying level of success.

After several years of testing a new technology has been developed to manufacture a composite sleeve using elastomers, fibers, and thermosetting resins. The sleeve is run-in on electric wireline, inflated to push the composite against the inside of the casing, then heated to polymerize the resins. The running equipment is extracted to leave a pressure resistant inner lining in place. There is little diameter loss, leaning access to the well below, and opening up applications for tubing repair. Following successful field trials commercial operations have begun.

The technology has been used not only for water and gas shut-off, but also for repairing damaged casings and tubings. This paper introduces the technology, describes the equipment used, and runs through the development and testing phases prior to beginning field operations. Typical examples of jobs carried out are cited, and some case histories are developed in greater detail.
Use of Full-Field Simulation to Design a Miscible CO2 Flood
Authors: Brinkman F. P. , Kane T. V. , McCullough R. R. , Miertschin J. W.
Published: December 2007

A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field three-dimensional geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house four-component simulator (stock tank oil, solution gas, water, CO2). A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood.
Reliability Analysis of Permanent Downhole Monitoring Systems
Authors: van Gisbergen S. J. C. H. M. , Vandeweijer A. A. H.
Published: December 2007

Permanent downhole gauge (PDG) systems have been installed in many oil and gas wells. These systems improve reservoir management and production optimization. Currently, more complex downhole monitoring and control systems are being installed in what are often called "Intelligent Wells." Reliability is a critical aspect for all these systems.

We evaluated the performance of 952 pressure- and temperaturemonitoring systems installed since 1987. The 5-year survival probability of these systems improved from 40% for systems installed in the period 1987–88 to 75% for the period 1991–92. No further improvements have been observed from 1992, resulting in a 5-year survival probability of 69% for the period 1993–98.

Failure modes have been evaluated and could be attributed primarily to the downhole gauge and to the cable. Based on these findings, recommendations have been made to achieve reliability improvements.
Simulation of Produced Water Reinjection Under Fracturing Conditions
Authors: van den Hoek P. J. , Matsuura Tsuyoshi , de Kroon Michiel , Gheissary Ghassem
Published: December 2007

An essential difference between conventional waterflood fracturing and unfiltered produced water reinjection (PWRI) under fracturing conditions is that in the latter case, the fracture conductivity cannot be assumed infinite anymore as a result of fracture fillup with injected solids. This relates to the important PWRI issue of where the injected solids go. Using numerical model calculations, we show that the pressure drop over a finite conductivity fracture can lead to a significant increase in fracture volume without necessarily leading to a significantly higher injection pressure. Thus, a picture emerges in which the fracture conductivity "adjusts" itself in order to accommodate injected solids. This picture allows the computation of well injectivity as a function of total injected water volume, solids loading, etc. This concept can also be used to qualitatively explain the PWRI field observation that injectivity appears to be partially or fully reversible as a function of water quality.

A field example from the Middle East is presented. The effect of parameters such as water quality, formation stiffness, and filter cake permeability on well injectivity and fracture size is discussed. It is shown that for most practical applications, an approximate analytical formulation for the computation of well injectivity and fracture size provides good results.
Effect of Near-Wellbore Fracture Geometry on Fracture Execution and Post-Treatment Well Production of Deviated and Horizontal Wells
Authors: Chen Zhongming , Economides M. J.
Published: December 2007

The near-wellbore fracture geometry is important to hydraulic fracture execution and the subsequent post-treatment well performance. A fracture from an arbitrarily oriented well "cuts" the wellbore at an angle and this limits the communication between the wellbore and reservoir. The stress concentration around the wellbore further complicates the near-wellbore fracture geometry. The fracture width at the wellbore can be much smaller than the maximum width, or it may even close when the fracturing pressure decreases below some critical value. The limited communication path may cause a "screenout" during fracture execution or large reduction in the subsequent production because of choked fracture effects. This paper first discusses fracturing conditions for an optimal communication path between the wellbore and the reservoir. The near-wellbore fracture geometry is then determined. The effects of this fracture geometry on fracture execution and production are discussed. Critical fracturing pressures are also calculated for different wellbore orientations and in-situ principal stress magnitudes. Guidelines are provided to enhance the success of fracturing treatments.
Underbalance or Extreme Overbalance
Authors: Behrmann L. A. , McDonald Bryan
Published: December 2007

Application of an extreme overbalance, sufficient to fracture the reservoir formation, applied either during or after perforating was first presented as an alternate completion technique during the 1993 Fall SPE Conference.1 During the ensuing two years, a number of jobs have been run by different operators in a variety of formations with varying applications. The primary question asked by an operator relates to the benefit of extreme overbalance (EOB) versus current perforation techniques of underbalance (UB) or modest overbalance for well control. Of course this question spawns a whole set of new questions about when and how to use and the benefits and risks of the EOB. EOB, as used in this paper, includes extreme overbalance perforating and rapid overpressured perforation extension. This paper compares and contrasts UB and EOB strengths and weaknesses and provides recommendations of when and why to use the different techniques. Field examples are provided of successful and unsuccessful application of EOB completions.
High-Permeability Channels in Proppant Packs Containing Random Fibers
Authors: Howard P. R. , James S. G. , Milton-Tayler David
Published: December 2007

This paper discusses laboratory studies to determine the nature of channel growth and stability in proppant packs with and without fibers. Tests were performed with proppant packs in three different types of experiments using natural sand and ceramic proppants, gas and water flow, and either perforations or an open proppant pack face. Proppant packs without fibers fail at low fluid velocities by the formation of voids at perforations or across the entire front ofthe pack. In proppant packs without fibers, channels form only in cases when packing is imperfect. Proppant packs with fibers form channels 2-10 cm wide, depending on fluid velocity. The channel length increases in stepwise progression with increasing flow rate (velocity). The proppant pack on either side of the channel supports the closure stress. Channels are stable over time at constant flow rate and remain stable during closure stress cycling. Channels grew with fibers in all conditions tested. Random fibers mixed with the proppant extend the fluid velocity range for channel growth to much higher values.
Evaluation of Clay Stabilizers for a Sandstone Field in Central Saudi Arabia
Authors: Nasr-El-Din H. A. , Al-Mulhem A. A. , Lynn J. D.
Published: December 2007

An oil field in central Saudi Arabia produces super-light crude from a sandstone reservoir. The formation contains up to 7.0 wt% authigenic clays dominated by kaolinite and illite/montmorillonite mixed layer clays. To mitigate sand production and improve well productivity, a frac pack stimulation treatment was conducted on most producing wells in this field. The treatment introduced several fluids, which might invade the formation and induce formation damage.

An experimental study was conducted to determine potential formation damage due to fines migration and clay swelling, and to design an effective clay stabilizer treatment. The work included performing coreflood experiments using reservoir cores under reservoir conditions. The critical salt concentration (defined, as the salt concentration below which there is loss of permeability) was first determined. Several commercial clay stabilizers, cationic polymers, were evaluated. The effects of stabilizer type, concentration and acids on core permeability were investigated in detail.

The experimental results indicated that the critical salt concentration (KCl brine) was nearly 5 wt%. Severe loss of permeability was observed when brines of lower salt concentrations were injected into reservoir cores. The effectiveness of clay stabilizers was found to be a function of chemical type and concentration. Some ofthe chemicals caused loss of injectivity at higher concentrations. It was found that these chemicals did not readily dissolve in water and formed fish eyes. When these chemicals were injected into reservoir cores, they formed an external filter cake, which caused loss of permeability. Good mixing of the stabilizer and proper filtration solved this problem. Hydrochloric acid at 15 wt% did improve the performance of at least one of the clay stabilizers examined.

Based on lab testing, a cost effective clay stabilizer was tested in the field. Field results indicated that the chemical did not cause loss of injectivity, and minimized formation damage due to fines migration and clay swelling.
Managing Structural Uncertainty in a Mature Field for Optimal Well Placement
Authors: Vincent Gilles , Corre Bernard , Thore Pierre
Published: December 2007

This paper describes a reservoir simulation study of a mature field. The objective of the study was to decide whether to drill an additional well and, if so, to determine its optimum location. An original approach to history-matching the model and accounting for structural uncertainty was adopted and we come to the following conclusions:

The structural map can be used as a history matching parameter, Maps with the same original oil in place (OOIP) can lead to quite different productions, The same production can be obtained from different maps having different OOIP, The choice of complementary development schemes must take the nonuniqueness of the history match into account in order to minimize risk, Demonstration of the use of experimental design techniques in accounting for and managing structural uncertainty.
Geochemistry in an Integrated Study of Reservoir Compartmentalization at Ewing Bank 873, Offshore Gulf of Mexico
Authors: Edman J. D. , Burk M. K.
Published: December 2007

Ewing Bank 873 is an offshore Gulf of Mexico field discovered in 1991 in 775 ft of water. The discovery well was drilled on a seismic amplitude anomaly on the flank of a salt withdrawal mini-basin. Field development began in 1994, and in mid-1998 daily production from the Bulminella 1 reservoir averaged 40,000 BOPD and 32 × 106 ft3/D of gas. The Bul 1 reservoir in this combination structural-stratigraphic trap consists of six stacked and overlapping Pliocene turbidite sand lobes. In turn, integration of seismic, well log, geochemical and pressure data indicates these six turbidite lobes comprise three compartments. All of the various data types give constraints on different aspects of compart-mentalization, but at the stratigraphically complex Ewing Bank 873 field, geochemical analyses provided key information unavailable through any other means. These geochemical analyses were performed as individual wells in the field went on production and immediately provided information regarding fluid communication and reservoir connectivity that was missing from earlier interpretations based solely on seismic and log data. Early recognition of three reservoir compartments using geochemical data also helped constrain preliminary stratigraphic interpretations and provided initial input for flow units and reservoir simulation models. The geochemical information further provided advance notice of economically significant oil quality variations in the three compartments. These fluid variabilities were later substantiated by pressure/volume/temperature analyses and include notable differences in oil gravity, weight percent sulfur, viscosity and solution gas. Integrating all available data shows there are three compartments at Ewing Bank 873 and each compartment comprises different turbidite sand lobes and exhibits its own characteristic pressure regime and fluid properties. The early indications of both compartmentalization and variation in fluid properties by the geochemical analyses contributed significantly to improved field recovery and economics by allowing fewer and better placed wells to be drilled.
Simultaneous Production of Gas Cap and Oil Column With Water Injection at the Gas/Oil Contact
Authors: Billiter T. C. , Dandona A. K.
Published: December 2007

The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities.