bluuebunny/crossref_metadata_2025 huggingface dataset:
Changes in Solids Composition of Reservoir Drill in Fluids During Drilling and the Impact on Filter Cake Properties
Authors: Pitoni E. , Ballard D. A. , Kelly R. M.
Published: December 2007

Considerable emphasis is placed on the selection of carefully sized bridging agents (including calcium carbonate, sized salt and cellulosic materials) for low damage reservoir drilling fluids. The rationale behind this selection is to optimise the filter cake-building properties of the fluids, and hence minimise formation damage due to invasion of mud particles into the near wellbore formation. This feature is particularly desirable in non-cemented completions where there are no perforations to bypass such near wellbore impairment. In addition the filter cake needs to be compatible with sand control techniques and equipment so that the productivity is not adversely affected.

Laboratory experiments on clean reservoir drilling fluids can, indeed, show the benefits of correct particle sizing, particularly in situations where the formations have high matrix permeability. There is some doubt, however, that these laboratory observations can always be repeated in the field, where the introduction of drilled solids and exposure of the fluid to high shear can result in a decrease of particle size.

The paper presents data from tests carried out on laboratory and field reservoir drilling fluids which show the extent and speed of the changes that occur in bridging solids composition and size distributions during drilling. The effects these changes have in terms of filter cake properties have been demonstrated.

Practical recommendations are made, which have been applied to wells drilled in West Africa. One well was a +600 m long horizontal section, where the filter cake was determined to have a neutral effect on the skin factor, without treatments for filter cake removal. A standard fluid would normally require a treatment, even if it is claimed to be non damaging.

Correct fluid composition, bridging material selection, and good maintenance of the drilling fluid system are the keys to success for better productivity. A filter cake that allows a better flow profile along the entire wellbore reduces the risks of water coning or erosion associated with non uniform flow and pressure drop. Very often, the cost of a specialised reservoir drilling fluid system is less than that of any treatment required to remove a standard filter cake and restore the original permeability along the entire borehole.
The Equation for Geopressure Prediction from Well Logs
Authors: Eaton Ben A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This study has resulted in the development of four equations that may be used for the prediction of geopressure magnitudes from well prediction of geopressure magnitudes from well log and drilling parameter data. Equations are given for use with resistivity plots, conductivity plots, sonic travel-time plots, and corrected "d" exponent plots. All equations have the same theoretical basis.

Introduction

In 1965, Hottman and Johnson presented a method for predicting geopressure magnitudes by using resistivity and sonic log data. This technique has received wide acceptance even though the prediction charts were based only on data concerning Tertiary age sediments in the Gulf Coast area. It was specifically pointed out that these techniques were applicable only in areas where the generation of geopressures is primarily the result of compaction in response primarily the result of compaction in response to the stress of overburden.

In 1972, this author presented a theory on the effect of overburden stress gradients n geopressure prediction techniques.

Compaction caused by overburden stress was described classically in a soil mechanics book by Terzaghi and Peck in 1948. With a vessel containing a spring and a fluid, they simulated the compaction of clay that contained water. Overburden stress was simulated by a piston, as in Fig. 1. It was shown that the overburden stress, S, was supported by the stress in the spring, sigma, and the fluid pressure, p. Thus, the long-accepted equation of equilibrium was established.

(1) S = + p

If Fig. 1 and Eq. 1 are studied, it is obvious that if S is increased and the fluid is allowed to escape, sigma must increase while p remains as hydrostatic pressure. However, if the fluid cannot escape, p must also increase as S is increased.

Hubbert and Rubey published a comprehensive treatment of this theory as related to sedimentary rock compaction. They showed that, as the overburden stress is increased as a result of burial, the porosity of a given rock is decreased. Therefore, some fluid that was once in the pores of a given formation was later squeezed out by compaction. In many such cases, there is no escape route for the fluid, and thus the fluid becomes overpressured according to Eq. 1. This happens in many areas, and such generated overpressured zones are often called "abnormal" pressure zones or "geopressure" zones.
A Comparison of Coal Seam Directional Permeability as Measured in Laboratory Core Tests and in Well Interference Tests
Authors: Wold M. B. , Jeffrey R. G.
Published: December 2007

A thick composite coal seam at Dartbrook Mine has been characterised by stress and permeability testing over several years. Most recently, a four well injection interference test was conducted to measure the overall seam permeability anisotropy, and core samples from various sites near the interference test array have been tested in the laboratory. The magnitudes of horizontal permeability components as measured by the well test and by core tests were found to be similar, but the principal permeability directions were reversed. The interference test measured the permeability anisotropy of the entire composite seam while the core samples came from only one of the four seams making up the composite seam. Structural features and hydraulic fracture results suggest that different seams and even parts of single seams in the composite seam are very likely to have significantly different permeability tensors.
Practical Issues With Field Injection Well Gel Treatments
Authors: Smith J. E.
Published: December 2007

Polymer gel treatments are effective in reducing high water production, resulting in improved oil recovery. The gels function by moving into highly permeable, water saturated zones and severely reducing permeability to water in those zones, so that oil can be produced from tighter rock. The gels can be applied to injection wells or producing wells. They are effective at shutting off water or gas in oil wells. This paper focuses on field applications of injection well gel treatments to shut off water in oil producing intervals. Strategies for sizing treatments in injection wells are discussed, and field case history examples are provided to illustrate concepts. Guidelines for predicting timing and magnitude of production side response are provided, along with economics and risk factors. A plot of normalized incremental oil response against gel volume injected is introduced as a new means of estimating expected oil response for heterogeneous sandstone reservoirs with crossflow, based on actual field performance of several injection well gel treatments.
Comparison of 20 Minnelusa Waterfloods in the Powder River Basin
Authors: Towler Brian F. , Griffith Durward B.
Published: December 2007

This study compares the oil produced at a projected pore volume (PV) produced predicted from a suitable curve fit. The study compares fresh waterfloods with brine floods. The data plots and curve fitting techniques are such that PV Oil produced could be chosen for the Y axis for easier economic analysis. This technique was developed and described in Griffith13. The study was originated from interest generated by work performed by Morrow's research group at the University of Wyoming, (see Tang26, and Tang and Morrow27), indicating that fresh water flooding could result in a greater oil recovery then saline floods. Table 1 and Figure 1 shows the comparison of our 20 chosen waterfloods. The Widge field, which extends above the top of the chart, has not produced sufficient water to define the waterflood. The lowest plotted field, the Spirit Field, appears to have watered out very quickly after initialization of the waterflood. Figures 2 and 3 are the 20 flood separated into non-enhanced and enhanced floods. The West Semlek waterflood is placed in the non-enhanced although an attempt had been made to use polymer in the field. We have assigned fresh water flood status to those fields initially flooded with Fox Hills water even though the later makeup water was combined with produced brines. The West Semlek, the one brine flood, is the flood in Figure 1 which has the x marker and intercepts the 2.0 pore volumes fluid (water plus oil) produced at 42% of OOIP produced. In general the fresh water floods had generally higher recoveries than the one brine flood, which is consistent with Morrow's laboratory results.
Risk Analysis - Is it Really Worth the Effort?
Authors: Newendorp Paul D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction

During the past 10 years or so there has been a concerted effort within our industry to expand the use of new quantitative evaluation methods in the analysis of how to invest capital in exploration and production operations. This effort has taken the form of many articles in our literature, numerous short courses and management seminars on decision making under uncertainty, and countless after-dinner speakers extolling the virtues of the new decision-analysis methods. In the process we have been exposed to a whole new vocabulary of terms such as risk analysis, expected value concept, conditional probability, EMV, decision trees, utility theory, Monte Carlo simulation, Bayes' theorem, bid strategies, etc. The common thread running through all of these new ideas has been the argument that, if we change from our traditional (and largely intuitive) ways of deciding how and where to invest capital and, instead, base our decisions on these new approaches, we will do a better job in the long term of investing capital under conditions of uncertainty.

The new decision-analysis methods involve quantitative statements of the degree of risk and uncertainty. Many involve complex, hard-to-grasp statistical concepts. And, outwardly at least, many of the methods suggest or imply that "scientific decision making" is really a very simple, impersonal review of a bunch of numbers. On the other side of the coin is the feeling of many managers that decision making is a very personal, intuitive, subjective, and emotional personal, intuitive, subjective, and emotional process that does not lend itself to any form of process that does not lend itself to any form of quantification by a staff of statisticians or management scientists.

Thus, it is not surprising that recent proposals to convert the decision-making process proposals to convert the decision-making process over to the new methods have caused much consternation, frustration, and skepticism on the part of many managers. Some have rebelled at the suggestion to change from the ways they have been using (successfully?) over the years. Others have concluded that the new quantitative analysis methods clearly offer important new insights about how best to invest money under conditions of uncertainty. But probably the large majority of decision makers are undecided about it all and are trying to assess the charges and countercharges being hurled back and forth between the "believers" and "nonbelievers." Their concern is whether to walk away from what they perceive to be the reasonably satisfactory (although largely intuitive) ways of making decisions they have been using for many years and embrace a new way of analyzing decisions that they only partially understand. partially understand.
Review of Coalbed Methane Development in the Powder River basin of Wyoming/Montana
Authors: Peck Charles
Published: December 2007

Coalbed methane development in the Powder River basin has a long history that is largely reflective of the uncertainty of the economics of the play, caused by a poor understanding of the reservoir. Conventional wisdom characterized the Wyodak and related coals as too shallow and too immature, having too much water and too little gas. Prior to 1986, gas shows in the Wyodak were encountered by ranchers, and water well drillers, and recorded by researchers. In 1986, conventional gas sands charged with CBM from the adjacent Wyodak coal were discovered and produced. In 1989, the relatively deep Big George coal was drilled in the Sasquatch Unit of Johnson County, without success. Rahwide Butte commenced production, with some success. Tax credits spurred continuous drilling of a limited number of CBM wells through 1992, many of which did not come on line until 1993. The Marquiss wells that started producing in 1993 became the first significant producers that began to indicate economic reserves and production rates. In 1994 the Macsy area came on line and added further credibility to the play. By 1997, sustainable production rates and apparent significant reserves caused and drilling of the play to increase significantly. During this long development period, a great deal was learned of the characteristics of the reservoir, the environmental and political aspects of operations, costs, and technical aspects. The economic limits of the play remain uncertain in areas where the Wyodak and Big George coals are deep, where hydrologic conditions differ from the "sweet spots", and where splitting of the coal causes difficulty in completions.
Restoration of the Natural State of Core Samples
Authors: Cuiec L.E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction

The wettability of a reservoir rock plays an important role in oil recovery during a water drive. It influences the residual oil saturation, the relative permeabilities and the capillary pressure. Since it is impossible to measure all these parameters in situ, laboratory experiments are used, thus raising the problem of the representivity of samples.

Most scientists working on the problem have concluded that it is difficult to obtain valid measurements without operating under conditions as close as possible to those in the reservoir.

It is easy to reproduce reservoir temperature and pressure conditions in the laboratory. It is also possible to obtain reservoir fluids. Unfortunately, obtaining porous-medium samples that are representative from the standpoint of the surface state is more delicate.

To obtain such samples, we can try either to preserve the original surface state or else to restore it. At the moment the former method is the most widely used, but requires special precautions while the sample is being taken. precautions while the sample is being taken. Nonetheless, these precautions are not sufficient to prevent a temperature and pressure drop when the sample is being brought up. This drop may change the distribution of fluids on the surface of pores and be accompanied by the deposition of asphaltenes or other heavy fractions.

In summary, the preservation technique as is now practiced is far from being perfect. Likewise, only modest confidence is generally placed on the quality of preservation. placed on the quality of preservation. It would be thus advantageous to have another method that could be applied whether the sample had or had not been cored with precaution and protected from any contamination, oxidation, fluid loss, etc., or whether or not it had already been used for physical measurements in the laboratory.

The restoration method meets these requirements. It consists of two steps:cleaning the surface of the solid to remove as much as possible if not all the products that had become possible if not all the products that had become fixed there, whether they came from crude oil or mud. It is not possible to separate the products initially adsorbed on the rock in the products initially adsorbed on the rock in the reservoir from those that had become fixed there afterward.
Results Of Acid-In-Oil Emulsion Stimulations Of Carbonate Formations
Authors: Bergstrom J.M. , Miller B.D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A low rate, low pressure stimulation technique using a new surfactant retarded, acid-in-oil emulsion has been found effective in providing better sustained production increases than previously obtained in stimulations using 15% and 28% hydrochloric acid in wells having high temperature, low permeability, carbonate formations. A permeability, carbonate formations. A fracturing technique also using the emulsion provided significant initial production provided significant initial production increases, but rapid declines occurred in most wells.

The results of 22 treatments using the low rate, low pressure technique and 12 stimulations using the fracturing technique are presented, and are compared to 80 previous treatments using 15% and 28% hydrochloric acid in wells having similar conditions.

Introduction

Commercial oil production was established on the Cedar Creek Anticline in Southeastern Montana (Central Williston Basin) in 1952, and major development drilling proceeded through 1965. Approximately 640 wells were drilled during this period on the narrow structure which extended for over 100 miles as shown on Figure 1. Major productive zones encountered were carbonates in the Silurian, Mission Canyon, Stony Mountain and Red River formations.

The area of interest of this study includes the Pennel, Coral Creek, Little Beaver and Little Beaver East Fields on the southern end of the anticlinal structure. The majority of production in the Pennel Field is from the Red River and Stony Mountain formations while production in the other three fields is production in the other three fields is predominently from the Red River alone. predominently from the Red River alone. With few exceptions, the wells are on 160 acre spacing. Average daily production from the four fields during 1974 was approximately 11,000 barrels of oil per day from 200 producing wells or an average of 55 BOPD per producing wells or an average of 55 BOPD per well. Each field is in a secondary recovery phase with waterfloods installed between 1965 phase with waterfloods installed between 1965 and 1969.

MATRIX TREATMENTS USING CONVENTIONAL ACIDS

During the early 1970's, Shell performed numerous low pressure, low rate stimulations (here defined as matrix stimulations) using 15% and 28% hydrochloric acid in wells throughout these four fields with modest success. Table I is a summary of the results of all matrix stimulations (a total of 80) that were performed during the period 1971 to 1974. performed during the period 1971 to 1974. Although many stimulations were performed before 1971, waterflood response was not generally noted in these fields prior to this time.
Understanding Proppant Flowback
Authors: Parker Mark , Weaver Jim , Van Batenburg Diederik
Published: December 2007

Proppant production from hydraulically fractured wells can cause severe operational problems, increase safety concerns, and dramatically reduce economic returns on well-stimulation investments. Methods that have helped eliminate or minimize proppant flowback include modified completion designs, the use of controlled fracture closure for obtaining early closure on the proppant pack, and the use of materials designed to reduce proppant production. Curable resin-coated proppants, chopped fiberglass, thermoplastic strips, and chemicals that modify the surface of the proppant are all accepted methods for minimizing flowback.

This paper presents the results of both physical and numerical modeling of proppant flowback recorded during the development of a chemical designed for modifying the proppant surface. The goal of this study was to develop an understanding of the mechanisms that control proppant flowback. Laboratory experiments performed in slot models with no closure stress helped establish the interaction of proppant size, proppant distribution, and fluid velocity. Additional studies of the impact of closure stress, fracture width, and fluid rate on proppant flowback were performed with modified API linear conductivity cells.

Data obtained from the physical modeling were used to calibrate a numerical model that predicts proppant flowback. In this model, fluid flow in the proppant pack is described by Darcy's equation for flow through porous media. The resulting velocity distribution allowed local stability to be assessed along the free surface between the proppant pack and the continuous fluid phase. Repeating these steps allowed evaluation of the interface that develops over time.
The Concept of Mud Weight Window Applied to Complex Drilling
Authors: Charlez Ph. A.
Published: December 2007

This paper deals with the concept of Mud Weight Window (MWW). In the first part, the classical case of passive basin is studied. It is shown that both impermeable shales and permeable reservoirs require overbalanced conditions, in the first case for stability reasons in the second to avoid a kick. It is then quickly explained how to determine MWW from logs in tight shales where direct measurements are not possible.

In the second part, some special complex cases are studied: unfissured and fissured formations, depleted fields, Extended Reach Wells, tectonic areas, deep water and HP/HT wells. In each case the specific MWW generates special problems. Several examples are discussed and operational solutions are proposed.
Optimization of NMR Logging Acquisition and Processing
Authors: Chen S. , Georgi D. , Fang S. , Salyer J. , Shorey D.
Published: December 2007

Successful petrophysical interpretation of NMR logs depends greatly on the selection of acquisition parameters and data processing methods. Routine tool calibration, based on a single fluid, guarantees the accuracy of porosity; however, the tool response to individual 72-components in a multiple fluid-component system is not directly assessed. The MRIL® response to multiple fluids was tested in a multi-fluid calibrator. A series of tests were performed in various logging modes, including standard T2, bound water logging, and dual wait time logging sequences. This investigation provides the basis for a more effective utilization of the MRIL tool with more appropriate acquisition parameters and data processing methods for the petrophysical interpretation of reservoir formation and fluid systems that exhibit bimodal T2 distributions.

For a given bimodal T2 distribution, the ability to detect bimodality depends on (1) the relative magnitudes of the two peaks, (2) the echo-train record length L, (3) the number of echoes N, (4) the data processing method including the proper bin range selection, and (5) noise. Based on the investigation, we discussed our recommendations for selecting acquisition sequences, parameters, and data processing methods.
Characterizing Sound Generated by Multiphase Flow
Authors: Wang Jianrong , van der Spek Alex , Georgi Daniel T. , Chace David
Published: December 2007

A new method for analyzing multiphase flow in wells using acoustic noise and capacitance log data is presented. Although using noise log to detect channeling is a well-established science for vertical wells, their interpretation in highly deviated and horizontal wells is difficult. Little attention has been paid to the shape of the spectra and their relationship to the multiphase flow or to their relationship to well deviation. The acoustic spectra can be decomposed into a background contribution, due to multiphase flow, and an extraneous component. Based on theoretical considerations, we explained the slope of the background spectra. The extraneous component is attributed to activities outside the casing or to fluid entries into the well.

There are two steps in interpreting the noise log data. The first step uses time series analysis of capacitance data to determine the flow regime. Then the noise generated by that flow regime can be characterized since each flow regime has a unique acoustic fingerprint (due to its unique turbulence structure). The second step is to identify the extraneous fluid flow signature. Sound generated by fluid channeling and fluid entry is superimposed on the background sound, which is generated by turbulent fluid motion inside the wellbore. Therefore, the deviation from background sound spectra is assumed to be caused by other sources, such as fluid channeling. Field examples indicate that the identification and characterization of background noise makes the acoustic log interpretation a valuable source for determining fluid channeling in multiphase flow horizontal wells.
Aqueous Systems for Paraffin Removal
Authors: Sutton G.D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in Houston, Tx., Jan 29–30, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

There are a variety of techniques used in the oil field to periodically remove paraffin deposited on downhole tubular goods periodically remove paraffin deposited on downhole tubular goods and in surface flow lines. Some of these removal methods may have certain drawbacks. Hot-oiling, a popular method of removing deposited paraffin, may contribute to formation damage if used repeatedly in low temperature, low pressure wells. This paper describes a water base chemical system which has been found to effectively remove paraffin from metal surfaces. A simple procedure is outlined in the text for testing aqueous paraffin procedure is outlined in the text for testing aqueous paraffin removal systems. A variety of applications for such a chemical system and some field results are also described.

Introduction

Deposition and accumulation of paraffin type deposits in the wellbore and surface flow lines often hamper production of crude oils. Very few fields in petroleum producing areas are completely free of paraffin problems. These paraffin problems may be so severe that the removal of the deposits must be done as often as once a week in order to maintain production. On the other hand, paraffin deposition may be only seasonal. That is, during cold paraffin deposition may be only seasonal. That is, during cold weather paraffin may only plug surface flow lines. These organic deposits can and often do present a constant source of aggravation to many field operators. Unless operators initiate systematic remedial treatments to remove these deposits, crude production gradually decreases, revenue is lost, and the possibility increases that expensive mechanical failures will result.

There are many reasons why paraffin deposits from crude oil. Reistle and many subsequent investigators have described the mechanism of paraffin deposition in great detail.
Drilling The Limit* – A Key To Reduce Well Costs
Authors: Schreuder J. C. , Sharpe P. J.
Published: December 2007

Well expenditure represents a significant part of Brunei Shell Petroleum (BSP) business, accounting for around 50% of capital expenditure. There is a significant value creation opportunity through achieving excellence in Well Delivery.

Drilling The Limit* (DTL) a Shell trademark, is an alternative planning methodology through which incredible time gains can be made, by applying resources and significant team effort with high focus on "soft issues". The concept was developed from extensive cross-Shell and cross-industry benchmarking including "Technical Limit Drilling"[1][2] and is based on extreme in-depth challenge of well design to identify what is theoretically possible. This theoretical limit forms a stretched target, representing a perfect world. The difference between historical performance and theoretical limit represents opportunity.

The DTL methodology was first tested in BSP on an offshore horizontal development campaign. These wells were delivered with a 40% time saving compared to historical performance, resulting in a 12% reduction in Unit Technical Cost. All these wells are producing above expectation.

This success delivered a performance "roller coaster", resulting in significant acceleration of subsequent wells, presenting a number of challenges for BSP. Resources required for DTL were under estimated as the accelerated work program resulted in even less time for detailed planning of follow up wells. A corporate study[3] confirmed what impact full implementation of the methodology would have on the organisation and its projected business results. Recognising its potential, BSP has planned for a wider application of the DTL methodology, the lessons learned to date are helping the company to plan for the impact of success.
Revitalizing The West Lutong Field
Authors: Pauzi N. , Low F. N. , Abas A. , Juwaini A. R. , Maksari H.
Published: December 2007

Reviving production from declining fields has become a major activity for oil and gas companies. This requires a focused multi-disciplinary team to arrive at a proper understanding of the reservoirs, identify for any remaining bypassed oil and the right technical solution. The West Lutong field is the oldest offshore field in the Baram Delta region located some 12-km offshore Sarawak, Malaysia. It has been on production since 1968 barely two years after the field discovery. The field has been under continuous development ever since, producing at 56000 bopd at its peak in 1972. Currently, the field is producing at 8000 bopd and is on a slowly declining trend. The field comprises a series of multiple stacked deltaic to shallow marine sandstone reservoirs that contain both oil and gas. The observed drive mechanisms consist of a combination of gas cap expansion, water drive and solution gas drive. In production time some of the units have been seen to be preferential swept. In June 1997 a multi-disciplinary West Lutong team was formed to identify bypassed oil and propose additional development. This paper focuses on the occurences of the bypassed oil and the remaining potential. This has enabled the formulation of an optimized development proposal to revitalize an aging field.
An Analysis of Finite-Difference and Finite-Element Techniques for Geothermal Reservoir Simulation
Authors: Faust Charles R. , Mercer James W.
Published: December 2007

A two-dimensional (areal) finite-difference geothermal model is presented, and results are compared with a Galerkin, finite-element model previously developed by the authors. In both previously developed by the authors. In both models, it is assumed that local thermal equilibrium exists and capillary pressure is negligible. The continuity equations for steam and water are reduced to two non-linear, partial differential equations posed in terms of fluid partial differential equations posed in terms of fluid pressure and enthalpy. These equations are pressure and enthalpy. These equations are applicable to both hot-water (single-phase) and vapor-dominated (two-phase) geothermal reservoirs

In both the finite-difference and finite-element models the time derivatives are approximated by finite-difference expressions. For each time step, this yields a system of nonlinear equations. The nonlinear coefficients are treated as constants during each time step and are evaluated using either the values of pressure and enthalpy at the beginning of the time step or values extrapolated to the mid-time level. In the finite-difference model the solution is improved by Newton-Raphson iteration. This technique markedly reduces mass and energy balance errors while permitting larger time steps. The linearized equations in both models are solved by a Gauss-Dolittle procedure for nonsymmetric, banded matrices. Several example problems, based on analytical solutions and published experimental data, are used to evaluate the relative merits of finite-difference and finite element techniques applied to geothermal reservoir simulation. Results suggest that the finite element method is more suitable for hot-water reservoirs due to less numerical diffusion and better approximations of boundary and internal geometries (with fewer node points). For vapor dominated systems, the finite-difference model appears superior because it reduces mass and energy balance errors and exhibits less numerical oscillation.
Numerical Simulation of Mass and Energy Transfer in the Longwall Process of Underground Gasification of Coal
Authors: Sawyer Walter K. , Shuck L.Z.
Published: December 2007

To mathematically describe the long wall generator process of underground coal gasification the coalbed is considered as solid carbon with a system of vertical micro-fissures along which combustion reactions occur. Mass and energy balances for the solid and gas phases and a mass balance for each hydrocarbon component are derived. Two overall reactions are considered resulting in seven coupled, nonlinear partial differential equations. partial differential equations. The primary mechanisms of heat transfer are conduction in the solid phase and convection in the gas phase. Also, convective transfer-between the two phases along the fissure walls, phases along the fissure walls, expansion of the fissure system and effective Darcy permeability as a function of distance and time, and temperature-dependent reaction rates are considered.

The equations are written in implicit finite-difference form and solved stepwise in one dimension by direct methods with systematic updating of coefficients. Solutions are obtained for the solid and gas temperature, total gas density, and mole fractions of oxygen, carbon dioxide, and carbon monoxide as functions of distance and time. Boundary conditions include input and output pressures, inlet gas and/or solid temperatures, and inlet oxygen concentration.

Typical sets of temperature and gas component concentrations along the generator length are shown. Curves are shown indicating the effect of the dimensions of the seam and the applied pressure gradient on the energy content pressure gradient on the energy content of the output gas. Also the subsurface energy conversion efficiency is discussed.
Identifying Fracture Geometry in the Appalachian Basin
Authors: Jacot R. Henry , Meyer Bruce R. , Myers Roger R. , Paugh Len O.
Published: December 2007

Identification of fracture geometry is necessary for the proper design and execution of a hydraulic fracture treatment. The Appalachian Basin consists of many different producing formations. These formations can vary in depth from 600 ft. to 7700 ft. Because of the low reservoir pressure (many of these formations are also underpressured) and low permeability, most of these formations require a hydraulic fracturing treatment to be economically successful.
Drill-In and Completion Fluid Formulation and Performance For Open Hole Gravel Packing Deviated Water Injection Wells Offshore Nigeria – A Case History
Authors: Seaton Simon
Published: December 2007

This paper is a review of two recent open hole gravel packed, water injection wells drilled from an offshore drilling rig, with particular focus on the loss of fluids and subsequent control of those losses, and makes recommendations for future wells based on the lessons learned. The techniques and fluids used to drill the deviated interval, place the gravel and remove filter cake prior to flowing back lost fluids and testing injectivity are discussed. The causes of loss of returns at various points during completion operations are identified and the remedial actions taken at the rig site are documented. Suggestions for future operations that should eliminate these losses are also outlined.

The drill-in and completion fluids chosen for these operations had to meet several criteria. In particular the bridging particles selected had to be a size range specifically chosen to effectively seal the formation of interest, and quickly form an impermeable filter cake on the surface of the formation, which prevented further invasion by the well bore fluids and subsequent reductions in formation permeability. Once the zone of interest had been drilled, the filter cake had to provide continued fluid loss control during displacements, placement of completion equipment and gravel pumping operations. However, at times potentially damaging losses were experienced. Once the gravel packing operation was complete, it had to be possible to remove the filter cake and bridging particles so that injectivity could be obtained, without plugging or bridging of the gravel pack or completion equipment. The techniques used to control losses also had to meet the same goals of preventing formation damage and avoid plugging of gravel and completion equipment.

The experience gained on these two wells shows that careful planning of fluids formulation, drilling practices and completion techniques are necessary to ensure the required fluid loss control while drilling and completing the well, especially while placing gravel. The filter cake formed can then be removed at the desired time to ensure maximum injectivity.
Reservoir Development Optimisation Utilizing Nuclear Magnetic Resonance Technology
Authors: Ogun Titus K. , Nwosu C. A. , Phillips O. O. , Jebutu Segun
Published: December 2007

From exploration to development, the challenges of cost-effective exploitation of hydrocarbon reservoirs are enormous and diverse. A lack of detailed understanding of the petrophysical building blocks of the reservoir in the early stages of its development usually constitutes a major impediment to achieving an efficient development strategy. In addition, stratigraphic and structural uncertainties exist and are only minimised as more wells are drilled to develop the reservoir. The hydrocarbon fluid types, accumulation, and stratification can also present complex uncertainties in identification and quantification, depending on the depositional environment of the reservoir.

The EE reservoir is structurally a rollover anticline with shallow marine deposits. It was discovered in 1965 and was put on stream in 1970. The reservoir has had 12 drainage completions to date, 7 of which currently flow with a total daily production of 7,100 BOPD. Until 1998, completion and development had been based on conventional data acquired at various time since the reservoir was discovered.

In 1998, a new nuclear magnetic resonance (NMR) logging device was run in the reservoir for the first time. Logs were acquired in well XT, which penetrates the southeastern flank of the reservoir. The results provided an improved definition of fluid flow units in the reservoir. The effective porosity was found to average between 32 and 34% with less than 2% variation across the reservoir. However, the bulk volume irreducible (BVI) showed considerable variation with depth across the reservoir, defining an egg-shaped flow-unit body. Permeability was on the order of 1.0 darcy, while the clay spectrum indicated laminated interbedded shales with clean sandstone layers cutting across the upper section of the reservoir. Core data from a nearby well was integrated with the NMR results, and a good correlation was obtained. Implications of these data on future completions and reservoir drainage strategy are highlighted in the paper.
North Apoi/Okubie Gas Condensate Development: Plan and Expectations
Authors: Akinlawon A.J. , Phillips O.O. , Hurel E.J.
Published: December 2007

This paper was prepared for presentation at the 23rd Annual International Conference and Exhibition held in Abuja, Nigeria, 4–6 August 1999.
Use Of Inert Gases In Well Completions
Authors: Horton Harry L. , Moran J.P.
Published: December 2007

Nitrogen and carbon dioxide have proved to be very effective production tools. In many fracturing and acidizing jobs, the use of one of these inert gases along with the stimulation fluid has improved the efficiency of the treatment, and sometimes made the treatment possible.

A review of case histories of many jobs using nitrogen and carbon dioxide as completion aids shows clearly the value of this technique as it is presently being used.

Before nitrogen and carbon dioxide could be put to use by the oil industry, it was necessary to develop special equipment that could move and handle them in the field. Now that this has been done, research efforts are being directed toward finding out more about the effects of these gases under simulated reservoir conditions so that present treating techniques can be improved even further.

Introduction

As early as January, 1938, portable well-service equipment was available for supplying limited quantities of low-pressure (100 psi) gas to aid in well-stimulation treatments.

Although the use of compressed gas increased the efficiency of acid stimulation treatments, use of the portable compressors limited this application to low-pressure wells where a low-rate treatment or a low gas-to-acid ratio was sufficient to help in return of the spent-acid solutions. High-pressure wells could be treated by this method only when a source of high-pressure gas was close to the well being treated. The weight and cost of a portable high-pressure, high-volume gas compressor for general field service made such a unit impractical.
Suspension Properties of Polymer Fluids Used in Drilling, Workover, and Completion Operations
Authors: Carico Robert D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

The ability of a fluid to suspend particles is essential to the successful particles is essential to the successful performance of fluids used in drilling, performance of fluids used in drilling, workover, and completion operations. The evaluation of a fluids-suspension ability has been by a comparison of the fluids' API Yield Point or by some apparent viscosity (i.e., funnel viscosity or viscometer apparent viscosity). This paper will present a simple, easy-to-use paper will present a simple, easy-to-use test for evaluating the suspension ability of a fluid, will give a ranking of some polymer fluids by their suspension ability, and will relate this ability to a low-shear-rate viscosity measurement of the-fluid.

Introduction

Fluids perform a variety of functions in drilling operations, including:Lift formation cuttings to the surface.Control subsurface pressures.Drill-string lubrication.Bottomhole cleaning.Provide an aid to formation evaluation.Provide protection to formation productivity.Prevent caving of formation.

The ability of the fluid to suspend particles is essential to the successful particles is essential to the successful performance of several of these functions. performance of several of these functions. This suspension capability is also important in other petroleum operations; for example, workover fluids and sand suspension in gravel packing and fracturing.

The evaluation of fluids for their suspending abilities has usually been by a comparison of their relative API yield points (YP) or by some apparent viscosity measurement; i.e., funnel viscosity or viscometer apparent viscosity (AV). Two main problems are encountered in using either of these methods. Firstly, it is almost impossible to compare fluids with different rheologies.
Investigation of Sulfide Scavengers in Well Acidizing Fluids
Authors: Nasr-El-Din H. A. , Al-Humaidan A. Y. , Fadhel B. A. , Frenier W. W. , Hill D.
Published: December 2007

This paper describes the development of acidizing systems that use several different aldehyde-based sulfide suppression chemicals in conjunction with new acid corrosion inhibitors. Specific combinations of these chemicals have allowed the acid to dissolve FeS, suppress H2S and still enable the acid to be inhibited to industry corrosion standards. Laboratory tests include dissolution of FeS, measurement of H2S evolved, measurement of acid concentration and chloride ion concentrations. We also determined the effect of FeS and H2S on the corrosion of oilfield steels with these additives. Laboratory measurements covered the temperature range from 75 to 275 °F (reservoir temperature).

Experimental results were compared with that previously published data.1 The new system enabled the acid to dissolve more FeS than fluids containing previously tested suppressors, while controlling H2S evolution and corrosion.

During field testing, samples of the spent acid were captured and were analyzed for [Fe], [S2−] and [HCl]. The data will contribute to an understanding of the corrosion processes and sulfide control during acid treatments. The field acid treatments were accomplished successfully without significant changes in procedures and resulted in large increase in gas production. This system is designed primarily for "tube cleaning" operations prior to acid stimulation (matrix and fracture acidizing), but the control chemicals have also been tested for use in the actual stimulation fluid stages.

The new chemicals and procedures will allow the operators to safely remove large amounts of fouling deposits, while controlling the toxic and corrosive effects of H2S much more effectively than previously used products.