bluuebunny/crossref_metadata_2025 huggingface dataset:
Mechanistic Investigation of the Formation Damaging Characteristics of Mixed Metal Hydroxide Drill-In Fluids and Comparison with Polymer-Base Fluids
Authors: Fraser L. J. , Reid P. , Williamson D. , Enriquez F.
Published: December 2007

Mixed metal hydroxide (MMH) fluids are highly thixotropic and have shown exceptional abilities in the areas of hole cleaning, suspension, and maintenance of good hole gauge even through very poorly consolidated sandstones.

When a drill-in fluid based on an MMH has been used in reservoir sections, the ease of cleanup and the production rates have both exceeded expectations. Results have been better than those achieved on offsets where more conventional fluids have been used. Laboratory results have also shown properly formulated MMH fluids to have a low potential for formation damage.

Most significantly, the low level of impairment runs contrary to results obtained with other (more conventional) bentonite-base fluids.

The primary objectives of the laboratory project presented in this paper were to (1) investigate the mechanisms by which filter cakes develop against sandstone faces, (2) study the natures of the cakes produced with different types of drill-in fluids, and (3) investigate the implications for cake cleanup.

In a group of unweighted fluids an MMH fluid was found to be unique in its ability to form a predominantly external cake. It was further shown that the strong interactions between the MMH crystals and the bentonite platelets, which interactions provide the characteristic high shear thinning and almost instantaneous gelling behavior of such fluids, also contribute to the avoidance of damaging internal cake formation. This study demonstrates by dynamic fluid-loss measurements, imaging of dried filter cakes using an SEM, and direct imaging of wet filter cakes using an environmental SEM that the fluid is able to form mineral bridges over pore throats in a wide range of reservoir rocks.

The external cake formed by the MMH fluid is easily removed by wash fluids or simply by application of backpressure as occurs when a well is brought on to production. Residual formation damage is minimal. This behavior has been observed in laboratory-prepared fluids and in fluids obtained from the field. In the case of the latter it has been shown that impovements occur in rheology, filtration control, and damage potential when the MMH product is added until a small excess is present.

Comparisons are made with sized salt and carbonate-weighted polymer muds. Also investigated was the effect of varying the size distribution of the carbonate weight materials in MMH and in polymer fluids.

The new understanding achieved with respect to the formation and nature of filter cakes provides direction for the formulation of drill-in fluids with a reduced potential for production impairment, and highlights areas for further investigation.
Interactions between Torque and Helical Buckling in Drilling
Authors: He X. , Halsey G. W. , Kyilingstad A.
Published: December 2007

The effects of torque on helical buckling are a concern in coiled tubing drilling. These effects are also important in conventional drilling of long horizontal wells.

This paper presents theoretical models for the effects of torque on helical buckling, normal contact force, and pitch of helix in the curved well bore. The effects of helical buckling and the post-buckling contact forces on torque and drag in a drilling operation are also modelled. The models are used for realistic simulations for both conventional drilling and coiled tubing applications.
Lithology-lndependent, High-Resolution Porosity Logs
Authors: Boyd A. , Head E. , Gubelin W. G.
Published: December 2007

A unique attribute of nuclear magnetic resonance (NMR) logging is the ability to measure a lithology-independent porosity. New NMR tools have generated renewed interest in measurements related to producibility, such as permeability and definition of water production potential. Industry discussion of those parameters has sometimes overshadowed the value of a lithology-independent porosity measurement. Such a porosity log can be easily understood by and utilized by non-specialists as well as log interpretation experts. The log reflects true porosity even in a complex lithology that changes over the well interval, such as limestone to dolomite transitions with evaporite inclusions. Similarly, since the log reads near zero in compacted shale, the measurement closely approaches effective porosity in clastic environments.

A new pad-type NMR logging tool produces such a porosity measurement with excellent vertical resolution. Investigation is focused within a volume whose vertical dimension is only 6 in. Examples from a number of wells illustrate excellent repeatability and resolution of thin reservoir components that are not visible with other NMR devices or conventional porosity logs. Logs are verified by core data and electrical images. The measurement is unaffected by borehole salinity, and the tool is combinable with other wireline tools.
Intrinsic Capture Cross-Section and Porosity Transforms for the TMD-L Pulsed Neutron Capture Tool
Authors: Jacobson L. A. , Ethridge D. R. , Wyatt D. F.
Published: December 2007

Environmental corrections to formation capture cross-section values (∑nf) measured with the new TMD-L tool are illustrated for a wide range of borehole conditions. A porosity transform for the near-far count-rate ratio is also developed. Test-pit measurements cover a range of intrinsic capture cross-section (∑int) values from 8 c.u. to 37 c.u. while porosities ranged from 2 p.u. to 38 p.u. Borehole sizes were 6, 8, 10, and 14 inches with casing sizes of 4-1/2, 5-1/2, 7, and 9-5/8 inches. Cement annuli up to 2-inch thickness were used. Effects of saltwater, freshwater, and gas (air) filled casings were determined. Regression techniques were employed in developing the algorithms to apply these corrections. They are typically capable of obtaining ∑int from the measured ∑fm, values to ± 1 c.u. over the range of conditions explored, even for gas-filled casings. The porosity transform for fluid-filled casing typically yielded the assigned test-pit porosities within ± 2 p.u. for casing sizes of 7 inches or less in boreholes of up to 10 inches. These transforms, which can be run in real-time, require as inputs the casing size, borehole size, casing liquid salinity (or gas), and cement salinity. One field log illustrates the utility of the intrinsic transform in removing the borehole effects such as at casing liquid-gas interfaces. Another example compares porosity from the TMD-L with neutron-density openhole porosity.
Applying Electrical Micro-Imaging Logs to Reservoir Characterization
Authors: Fam M. Y. , Chemali R. , Seiler D. , Haugland M. , Stewart W. F.
Published: December 2007

Integrated analysis of two-dimensional and three-dimensional images from electrical micro-imaging devices provides a powerful link between core measurements, traditional logging information, and methods of reservoir characterization. Side-by-side comparisons of electrical images and core photographs illustrate the value of this technique for understanding stratigraphic and structural relationships in a given formation. The derivation of a high-resolution quantitative resistivity log from an electrical micro-imaging device offers enhanced petrophysical analysis in highly laminated reservoirs. This quantitative resistivity log, characterized through a three-dimensional electrical modeling code, exhibits a depth of investigation comparable to the shallow laterolog, digitally focused log, or short guard log.
Wireline Fluid Sampling
Authors: Michaels John , Moody Mike , Shwe Than
Published: December 2007

Accurate PVT data are crucial to well completion and production, formation evaluation and reservoir characterization. This is especially true for initial reservoir characterization where the PVT sample needs to be obtained prior to production. It is essential that the fluid sample be recovered as closely as possible to in-situ conditions whether by drill stem or wireline formation tester. The need to remove drilling mud filtrate prior to collecting a sample has been widely recognized. Wireline testers which can pump fluid from a formation until filtrate is reduced to a minimum overcome this problem. While reducing sample contamination has been addressed, little emphasis has been placed on the need to control inlet pressure during filtrate removal or during sampling. Reducing contamination is important; however, there is equal need to determine the critical sampling pressure. The purpose is to prevent phase separation in the formation by regulating the sampling process based on this information and thereby obtain a more representative reservoir fluid sample.

A recently introduced wireline instrument provides the capability of measuring the critical pressure prior to sampling, of controlling the sample pressure and of increasing the pressure in the sample container to compensate for temperature decline during delivery of that sample to a testing laboratory. Example of pressure tests while pumping and during pressure buildup are presented along with indicated sample properties.
A Rheometer for Evaluating Drilling Fluids at Elevated Temperatures
Authors: Garvin Thomas R. , Moore Preston L.
Published: December 2007

The trend toward deeper wells with subsequent higher bore-hole temperatures has increased the need for data on drilling fluid properties at elevated temperatures and pressures. Equipment presently available does not allow direct presently available does not allow direct determination of fluid properties from lower laminar to fully turbulent flow with precision. This paper presents the design precision. This paper presents the design considerations that led to the construction of equipment at the University of Oklahoma to provide high temperature data for drilling fluids and cement slurries and examples of such data for three drilling mud systems.

The equipment will operate up to 350 degrees F through flow ranges from lower laminar to turbulent flow with sufficient precision for extrapolation to other precision for extrapolation to other pipe sizes and other geometries of flow pipe sizes and other geometries of flow conduit.

It was determined that the equipment was adequate and that the fluid properties of at least some fluid systems properties of at least some fluid systems are highly dependent on temperatures and should be examined by this procedure for critical design programs.

Introduction

Several investigators have recently been interested in the high temperature behavior of drilling fluids due to the increasing numbers of deep wells and the need to critically control drilling fluid rheology in these wells. The experimental methods and the chosen form of data presentation vary considerably among the presentation vary considerably among the various investigators but all have indicated a deleterious effect on drilling fluid caused by a high temperature environment. Many of the investigators have tried to relate the deleterious effects to measurable chemical or physical changes that occur in clay drilling fluids at elevated temperatures.

Most of the previous investigators have chosen to study the rheological properties of drilling fluids at elevated properties of drilling fluids at elevated temperatures with a modified rotational viscometer and report the data considering the fluids as Bingham Plastics.
Colloquium on Petroleum Engineering Education: A Summary
Authors: Russell J. E. , Broussard N. J. , Tiedemann H. A.
Published: December 2007

The third Colloquium on Petroleum Engineering Education (CPEE’95), a part of the SPE Forum Series, was held July 23–28 al the Wildwood Lodge in Snowmass Village, CO, with sponsorship from the U.S. Department of Energy (DOE), industry, and SPE.

Seventy-two people participated in CPEE’95: 46 (64%) Academics (13 of whom were internationally based), 22 (31%) Industrial Representatives (1 from the Netherlands), and 4 (5%) Government Representatives [one each from the U.S. Department of Energy and the National Science Foundation at the Oak Ridge Institute for Science and Technology Education (ORISE), and two from Sandia National Laboratory].

The focus of CPEE’95 was adding value to Petroleum Engineering education for both the individual and industry. Eight primary sessions and one summary session were held. The program was balanced between academic, industrial, and government presenters. Four sessions were developed by planning committee members from industry and four by planning committee members from universities. The summary session was developed by committee members from academia and government

The development of several model curricula and an action plan to implement the plan received the greatest amount of effort. Model curricula were developed by five breakout teams that maintained the same membership throughout the colloquium. The curricula were initially unconstrained, with constraints being added as the colloquium developed.

These model curricula contain the following common themes: An increased emphasis on the geosciences;The importance of teamwork;Increased exposure to financial, regulatory, and risk strategy topics; and finallyAn emphasis on fundamentals, problem solving, lifelong learning, and education--rather than training in current technologies.

CPEE’95 participants also discussed the proposed changes in evaluation criteria given by the Accreditation Board for Engineering and Technology (ABET), where these criteria will present both constraints and opportunities for petroleum engineering education.

The action plan includes creation of three task forces: International Cooperation--a task force to address issues of interaction and parity among programs world wide,ABET Draft Criteria--a task force to give the SPE E&A Committee guidelines for proposed criteria changes and to assess the value of developing a vehicle for the discipline-specific portion of the registration examination, andDOE/Industry Fellowship Program--a task force to work with Craig Williamson (DOE ORISE, Oak Ridge) to develop a graduate fellowship program for U.S. citizens.
The Drilling Porosity Log "DPL"
Authors: Zoeller William A.
Published: December 2007

The Drilling Porosity Log (DPL) is a formation porosity log derived from a mathematical treatment of detailed drilling information. The basic concept of the DPL is that the porosity of a particular rock effects the way that rock is drilled in a definable manner.

Comparison of the DPL and logs from standard wire line porosity tools from several areas are presented and discussed.

A generalized, non-mathematical explanation of the derivation of the log is presented.

Introduction

For many years, penetration rate has been used for correlations, drilling breaks etc. It was assumed that variations in rate of penetration represented formation properties. However, many false properties. However, many false interpretations resulted when the rate of penetration change was a reflection of some penetration change was a reflection of some human or mechanical change in the drilling operation rather than the result of a formation response. To overcome this difficulty efficient drilling operations were sacrificed to control constant as many of the variables of the drilling operation as possible, thereby avoiding false interpretations of the rate of penetration curve or the expense of a correlation log run. Such efforts not only sacrificed drilling efficiency, they were also impractical in most cases. For example a sufficiently motivated operator might maintain constant weight on bit and maintain a constant rotary speed but he would be hard pressed to control the bit tooth dulling or changes in formation pressure, both of which can dramatically pressure, both of which can dramatically effect the deflection of the ROP curve.
Two-Phase Pump Transient Behaviour
Authors: Bratu Ch.
Published: December 2007

Concerns regarding the efficiency, stability and safety margins of the rotodynamic pump POSEIDON P300 unit has prompted the investigation of steady state and transient behaviour.

Bench tests, carried out on the IFP - Solaize multiphase loop, precede long term field endurance trial (TOTAL -Tunisia).

The paper introduces a global analytical model enabling the understanding of the transient pump behaviour. Experimental results are analyzed and gathered pratical conclusions enable the design of the control-regulation system.
Multiphase Pumping: The Lessons of Long-Term Field Testing
Authors: Leporcher E. , Taiani S.
Published: December 2007

The field testing of a POSEIDON rotodynamic helicoaxial pump (P302) manufactured by SULZER is being conducted since June 1994 on the Elf Aquitaine's onshore site of the PECORADE oil field located in the south-west of France. This one-year testing program is aimed at qualifying this design of multiphase pump for future field applications. The multiphase pump has been previously tested at the IFP's test loop of SOLAIZE for factory acceptance and performance test [1].

This paper describes the PECORADE multiphase loop, the multiphase pump testing procedures and the results obtained in the field of performance, sensitivity, and endurance. The operational and maintenance lessons to be learned from this long-term field testing are presented from the point of view of the operator.
Numerical Simulation of Pressure Behavior In a Fractured Reservoir
Authors: Chiang C.P. , Kennedy W.A.
Published: December 2007

A simulation model of a reservoir with a symmetrical-horizontal fracture extending from the wellbore to the midpoint of the drainage radius was constructed.

The mathematical equation was developed for the case of single-phase unsteady state fluid flow. A solution for an infinite reservoir was obtained numerically and used for pressure drawdown and buildup analysis. The pressure drawdown and buildup analysis. The numerical results shows that:

1. On pressure drawdown and buildup curves, two straight lines are obtained; the first straight line with lower slope yields the effective permeability of the matrix and fracture, and the second straight line with greater slope yields the permeability of matrix.

2. The time of bend between the straight lines increases with increase in fracture radius. As the fracture radius approaches infinity, only one straight line of the Odeh type is obtained.

3. Extrapolation of the first straight line portion of the buildup curve may lead to an incorrect value of the static reservoir pressure.

Introduction

Analysis of pressure buildup and drawdown data is recognized as a powerful tool by the production and reservoir engineer seeking to production and reservoir engineer seeking to characterize the reservoir. Most pressure analysis techniques have assumed homogeneous reservoirs, i.e. the porosity and permeability are constant. However, some prolific wells produce from fractured reservoirs. These produce from fractured reservoirs. These reservoirs contain two distinct types of porosity and permeability, namely fracture porosity and permeability, namely fracture and matrix. Since the fractured region has higher permeability, reservoir-engineering analysis based on a homogeneous reservoir may lead to erroneous results. The purpose of this study is to develop a mathematical model which will simulate the pressure drawdown and buildup curves that would be obtained from a reservoir with a symmetrical-horizontal fracture around the wellbore. The mathematical model is developed by assuming a cylindrical reservoir of drainage area of uniform thickness is penetrated by a single production well at its center. The two -dimensional diffusivity equation for single phase flow was used to obtain pressure buildup phase flow was used to obtain pressure buildup and drawdown curves. It was necessary to obtain a constant rate solution to the equation because of the mathematical complexities introduced by the fractured reservoir geometry.
Economic Analysis of Drilling Fund Programs
Authors: Ambler Alan C.
Published: December 2007

The "Drilling Fund" method of financing oil and gas exploration and development has mushroomed in recent years and has become an important part of the independent's source of capital. This paper compares the various types of fund programs available, primarily from the investigators point of primarily from the investigators point of view. The investor's side is taken rather than the operator's because drilling fund participation interests have to compete with participation interests have to compete with other forms of investment in the capital marketplace, and fund was are not easy to sell to the prospective investor. Oil operators need to know and understand their investor partner's expectations, tax problems, and other reasons for getting into the oil business through the drilling fund medium.

Most fund programs are limited partnerships whereby the oil operator is the general partner and the limited partners are a group partner and the limited partners are a group of high-tax-bracket investors. Other programs are joint ventures between operator programs are joint ventures between operator and investors. The economic comparisons in this paper are based on typical or "average" industry statistics for finding and developing domestic onshore oil and gas reserves. The types of fund structures compared are (a) All costs paid by investors — operator has straight overriding royalty interest, (b) All costs paid. by investors — operator has back-in interest after payout, (c) Investors pay all intangible costs, operator pays all tangible costs, income is shared.

If the government does not interfere, drilling fund programs will have an increasingly important influence on exploration and development operations in the future.

Introduction

Over the next decade there is going to be an ever widening gap between the supply of hydrocarbons in the United States and the demand for these natural resources.
Laboratory Evaluation of Waterflood Behavior of Vugular Carbonates
Authors: deZabala E. F. , Kamath J.
Published: December 2007

Laboratory evaluation of waterflood behavior of vugular carbonates is subject to significant uncertainty. Even basic parameters such as residual oil saturation are difficult to estimate and depend on experimental conditions. We use X-ray Computed Tomography (CT) scanning to characterize the porosity, permeability, and waterflood displacement behavior in rocks from two carbonate settings. We find that the porosity and permeability distribution are dissimilar. This causes the dependence of their residual oil saturation on water flow rate to be very different. We attempt conventional methods to extract meaningful information from the data but find them inadequate.
What is Being Done About the Natural Gas Shortage
Authors: Sampson H.M.
Published: December 2007

A natural gas shortage has definitely been established. Experts agree that demand has, and will continue to out-strip supply.

The Federal Power Commission has overcompensated in trying to protect the ultimate consumer from the standpoint of price - - with the result that they have price - - with the result that they have failed to protect him on supply.

This myopia must now give way to some reasonable basis of reflecting fair market value, which will not be subject to future change. Industry must be encouraged to solve its own problem. Gas from Canada, Alaska, synthetic fuels, and liquid from foreign sources and nuclear stimulation offer a possible supplemental source of supply.

Fortunately, the Federal Power Commission and its staff now fully recognize this serious problem that confronts the industry and is now planning some possible solutions.

The industry and government must accept the financial and moral responsibility for a vigorous unrelenting search which must be conducted to find the gas necessary to maintain a viable industry, protect the consumers and the national interest.
The Engineer's Relationship to Oil Spill Laws and Regulations
Authors: Spurlock R.C.
Published: December 2007

Introduction

Increased awareness of laws and regulations pertaining to oil spills will be required of engineers in the petroleum industry during the decade of the '70's. We have already seen a number of instances where operators have been cited and eventually fined for violation of one of the several statutes which cover accidental or deliberate release of oil or similar materials.

For the purpose of our discussion today, I will restrict my comments to applicable federal laws and regulations and will exclude any reference to state or local regulations. In order to understand where we are today, it seems appropriate to briefly review the historical development of antipollution or environmental legislation.

RIVERS AND HARBORS ACT OF 1899

As early as 1899 the Congress passed the Rivers and Harbors Act, sometimes called the Refuse Act, which included the following:

It shall not be lawful to throw, discharge, or deposit, or cause, sufferor procure to be thrown, discharged, or deposited either from or out of anyship, barge, or other floating craft of any kind, or from the shore, wharf, manufacturing establishment, or mill of any kind, any refuse matter of any kind or description whatever other than that flowing from streets and sewers and passing therefrom in a liquid state into any navigable water of the United States, or into any tributary of any navigable water from which the same shall float or be washed into such navigable water: … whereby navigation shall or may be impeded or obstructed.

Clearly, the intent of the legislators who drafted this bill over 70 years ago was to prohibit the dumping of floating refuse which prohibit the dumping of floating refuse which could be a danger to marine navigation.

Interpretation by the courts over the years, however, has enhanced the usefulness of the Rivers and Harbors Act of 1899 in controlling and abating pollution in our nation's rivers and streams. As recently as 1966, the U.S. Supreme Court stated: "The word 'refuse' includes all foreign substances and pollutants apart from those 'flowing from streets and sewers and passing therefrom in a liquid state' into the water course."

This broadening of the original language has permitted enforcement agencies to apply the 1899 law to current antipollution activities, especially in the area of oil spills.
Design of Pipelines for the Simultaneous Flow of Oil and Gas
Authors: Baker Ovid
Published: December 2007

Measurements were made of pressure drops for oil and gas flowing simultaneously through four to ten inch diameter pipelines. These results were related with data from the literature for one-half to three inch diameter pipelines. Previously published data were used to construct a generalized chart for predicting the type of flow pattern in the pipeline. The flow patterns described are bubble flow, plug flow, stratified flow, wavy flow, slug flow, annular flow, and spray flow. Our experimental data were shown to be consistent with the generalized flow pattern chart.

The calculation method proposed by Lockhart and Martinelli for designing two-phase pipelines was shown to be inadequate for larger diameter lines and also for some flow patterns. Modifications of the above method in the form of separate equations for each type of flow pattern are presented.

Introduction

In recent years there has been an increasing tendency to transport both oil and gas simultaneously through pipeline gathering systems. Trends toward central separator batteries, crude stabilizations, and total well stream processing in distillate type fields have emphasized the need for better information on the effects of liquid flowing along with the gas in pipelines.

The many fold increase in pressure drop when liquid is deliberately put into a gas pipeline is illustrated by Van Wingen's data in Figure 1. A look at the mechanism of two-phase flow will explain why pressure drops increase so much.

When two phases flow through the same pipe the gas usually flows faster than the liquid. The liquid accumulates in the pipe and reduces the cross sectional area available for gas flow. The pressure loss of a fluid flowing through a pipe is inversely proportional to the fifth power of the pipe diameter. The accumulated liquid in the line has the effect of reducing the diameter. A reduction of 20 per cent in diameter would cause a three fold increase in pressure drop, while a 60 per cent reduction would increase pressure drop one hundred times.

At some ratios of gas to liquid flowing, the surface of the liquid is very disturbed. There are many projections of liquid waves or ridges into the gas stream. For a half century studies have been made of the effect of roughness of inside pipe surface on pressure drops. Various friction factor charts taking roughness into account are available.
Predicting Gas Reserves in Abnormally Pressured Reservoirs
Authors: Hammerlindl D.J.
Published: December 2007

This paper is a study of abnormally high-pressured depletion-type gas reservoirs. In these reservoirs two distinct slopes are evident when a plot of shut-in bottom-hole pressures vs cumulative production (P/Z plot) pressures vs cumulative production (P/Z plot) is used to predict reserves. The final slope of the P/Z plot is steeper than the initial slope; consequently, reserve estimates based on the early life portion of the curve are erroneously high. The initial slope is due to gas expansion and significant pressure maintenance brought about by formation compaction, crystal expansion and water expansion. The early performance of the reservoir, as it appears on a P/Z plot, is due to the effective compressibility of the system. Effective compressibility varies from gas compressibility (theoretical P/Z performance) by the effects of the above mentioned pressure maintenance. At approximately normal pressure gradient the formation compaction is essentially complete and the reservoir assumes the characteristics of a normal gas expansion reservoir. At this point effective compressibility is about equal to gas compressibility, and this accounts for the second slope. Many costly decisions are based on the early life extrapolation of the P/Z plot. Therefore, it is necessary that we plot. Therefore, it is necessary that we understand the effects of hydrocarbon pore volume change on reserve estimates, productivity and abandonment pressure.

Two methods have been derived for correcting reserve estimates from the early life data using formation compressibility, gas production and shut-in bottom-hole pressures. The first method uses the ratio of the average effective compressibility to the average gas compressibility, while the second method includes compressibility in the expansion term of the material balance equation. The developed corrections are accurate in theory, but such required information as formation compressibility is based on limited empirical data. This must be kept in mind when using the family of curves provided in this paper. An effort has been made to help establish abandonment pressure and to reconcile other related compaction problems.

Introduction

This paper is a study of abnormally high-pressured depletion-type gas reservoirs. In these reservoirs two distinct slopes are evident when a plot of shut-in bottom-hole pressures vs cumulative production (P/Z plot) pressures vs cumulative production (P/Z plot) is used to predict reserves. The final slope of the P/Z plot is steeper than the initial slope; consequently, reserve estimates based on the early life portion of the curve are erroneously high. The initial slope is due to gas expansion and significant pressure maintenance brought about by formation compaction, crystal expansion and water expansion.
Effects of Drilling Fluids on Gas Well Productivity
Authors: Methven Norbert E.
Published: December 2007

This paper defines a method of increasing gas recovery and reserves by maximizing natural gas well deliverabilities. This method involves prevention of formation damage while drilling, prevention of formation damage while drilling, completing, and working over gas wells.

Included is the definition of the formation damage mechanisms attributable to drilling, completing, and working-over operations. Formation damage, the principle deterrent to maximum-productivity and recovery, involves the physicochemical relationships of fluid-systems with the formation. These relationships are herein defined and then specifically extended to include the effects on gas reservoirs. Of particular importance is a treatise on the effects on the relative permeability to gas from hydrocarbon invasion. permeability to gas from hydrocarbon invasion. This treatise includes a means to evaluate the vaporization-equilibrium constants of the invading complex hydrocarbons. These principles have then been used to develop an oil base fluid system that precludes formation damage and that has a filtrate that will be vaporized by produced gas to preclude any reduction in produced gas to preclude any reduction in relative permeability to gas.

Also presented are computed data, laboratory data, and field data from wells drilled and completed with various fluid systems. These data include core data, return permeability data, back-pressure tests, well productivity histories, and pressure buildup surveys. These data show substantially increased initial and ultimate income from gas wells when non-damaged completions are effected.

Introduction

The current and forecasted natural gas shortages increase the importance of maximizing the initial productivity and ultimate recovery from gas wells. A frequent impediment to maximum well productivity and hydrocarbon recovery is formation damage that may occur during the drilling or completion operations.
Case History: Comparison of Advanced MWD and Wireline Resistivity Tools in Thinly Laminated Reservoirs, Offshore, Trinidad
Authors: May Bruce , Dattoo Bobby , Roeth Richard , Oberkircher Jim
Published: December 2007

A direct comparison of the two most advanced resistivity devices currently in use, the MWD based EWR Phase 4TM and the wireline run Array Induction Tool (AIT)TM, is made. Both tools were run in a well drilled off of the East Coast of Trinidad by Amoco Trinidad Oil Company. The tools are run in their respective environments to enhance reservoir identification and characterization in thin, highly laminated reservoirs. The objective interval in this area was thought to have this type of reservoir characteristic, Both use multiple depths of investigation combined with good vertical resolution to determine true resistivity (Rt) and to identify invasion profiles. A comparison of the results of the tools are related to previous efforts with other logging devices and actual production results. The two tools are compared through both thinly laminated and thick sand sequences.

Introduction:

Samaan B-8(ST)X well in Samaan Field, offshore Trinidad provides an opportunity to compare resistivity log response between the MWD EWR Phase 4 tool and a high resolution wireline resistivity tool such as the Array Induction Tool in a thinly laminated sandstone reservoir. Recognition of pay in thinly laminated low resistivity sand sequences similar to the Samaan Field 4B Sand reservoir is important in an active exploitation program in this field. The EWR Phase 4 and the AIT obtain resistivity information under differing borehole and invasion conditions. Both resistivity devices respond to the thinly laminated nature of the 4B Sand reservoir.

Tool Specifications

EWR Phase 4

The EWR Phase 4 (Figure 1.) is a multiple depth of investigation MWD resistivity device that uses four transmitter receiver spacings. From these spacings, different depths of investigations can be derived using phase, attenuation or a combined phase/attenuation based measurement. The spacings include X-shallow (EWXP, 6-12 inches radius of investigation); Shallow (EWSP, 12-18 inches); Medium (EWMP, 24-30 inches); and Deep (EWDP, 36-40 inches). The three shallower reading devices propagate at a frequency of 2 MHz, while the deep reading curve is at 1 MHz.

The Array Induction Tool

The AIT Tool (Figure 2.) is also a multiple depth of investigation resistivity device. It utilizes 8 mutually balanced induction arrays, whose main coil spacings range from a few inches to several feet. A single transmitter coil operates simultaneously on several frequencies between 105 Hz to 104 Hz range.

P. 747
A New Analytical Method to Evaluate, Predict, and Improve CO2 Flood Performance in Sandstone Reservoirs
Authors: Bou-Mikael Sami
Published: December 2007

The Port Neches CO2 flood (Fig 1), is a joint project between the Department of Energy (DOE) and Texaco E&P Inc. (TEPI) that has been operating for nearly 3 years. This project represents another learning step in developing the CO2 technology. This paper serves as a vehicle for transferring the technology acquired by TEPI to the industry.

Reservoir selection for miscible CO2 injection is critical to the economical success of any new project. Vast amount of potential reserves throughout the Gulf Coast are awaiting the right application of CO2 technology. Identifying these reserves, selecting the appropriate recovery method and accurately predicting the recoverable reserves and recovery rates are the essential ingredients of a successful project.

This paper include a brief discussion of the Port Neches project performance to date and presents a methodology to select, evaluate and predict project performance based on analogy with other projects performed throughout the Gulf Coast. This analytical approach utilizes type-curves developed from several CO2 floods and can be used independently or in conjunction with other available methods such as reservoir simulation.

Introduction

The vast majority of CO2 flood projects today are being conducted in carbonate reservoirs in the Permian Basin. Industry efforts in the Gulf Coast have been limited in scope and usually on a smaller scale. Gulf Coast sandstone reservoirs differ from those in the Permian Basin in terms of their matrix, reservoir architecture, oil composition, drive mechanism and recovery rates. Their suitability to CO2 flooding also varies.

The principal objective for CO2 projects in the Gulf Coast Region in the past has been to achieve miscibility early in the life of the project in order to maximize recovery. This objective has focused the oil industry for CO2 candidates selection on high pressure strong water-drive reservoirs in order to attain miscibility quickly. These water-drive reservoirs have very low residual oil saturation in the swept area, Which has often led to poor performance under CO2 flooding.

P. 177
Improved Oil Recovery for Independent Oil & Gas Producers
Authors: Sgro Anthony G. , Kendall Richard P. , Kindel Joseph M. , Webster Robert B. , Whitney Earl M.
Published: December 2007

There are more than fifty-two hundred independent oil and gas producers operating in the United States today (based on current IPAA membership figures). Many of these companies have instituted improved oil recovery programs in some form, but very few have had access to the state-of-the-art modeling technology routinely used by major producers to manage these projects. Since independent operators are playing an increasingly important role in production of hydrocarbons in the United States, it is important to promote state-of-the-art management practices, including the planning and monitoring of improved oil recovery projects, within this community. This is one of the goals of the Strategic Technologies Council, a special interest group of Independent Oil Gas producers.

This paper will describe a project which focuses on the distribution of advanced reservoir management technologies (geological, petrophysical, and engineering) to independent producers. The evolving information highway, specifically the World Wide Web (WWW), serves as the distribution medium. The procedure for launching petrotechnical applications and retrieving results over the WWW will be presented. A paradigm for the interaction between the independents, the petroleum service sector, and government will also be presented. Of principal concern is the cost of making high-tech modeling applications accessible to independent operators.
DOE's Class 1 Projects: Delivering Results
Authors: Cole E. Lance , Grabhorn Merle D.
Published: December 2007

Industry cost-shared field demonstration projects being conducted in fluvial-dominated deltaic (Class 1) reservoirs as part of the Department of Energy’s (DOE’s) Reservoir Class Program are demonstrating cost-effective, practical technologies. Reserve development costs are less than or competitive with exploration or acquisition costs. Prudent technology applications are starting new waterfloods, giving new life to mature water-floods, creating successes in reservoirs where waterflooding previously failed, and starting successful waterfloods in reservoirs previously thought to be unsuitable for waterflooding. Successful field demonstration and technology transfer efforts are spawning additional technology applications outside DOEs Reservoir Class projects.
Reducing Electric Power Costs in Old Oil Fields
Authors: Paik M. E.
Published: December 2007

In older oil fields, the cost of electric power is one of the larger, if not the largest, operating cost. Field profits can be improved by focusing on oil production profits rather than oil production volumes. This requires different paradigms for managing electricity and different paradigms for field operating practices. This change in focus is essentially procedural, generating significant increases in economically recoverable reserves at minimum incremental investment.

This paper is directed primarily at the oil fields of the contiguous USA, (Lower 48 States). Conditions effecting electricity availability, usage & price differ significantly elsewhere in the world.
A New Concept for Improving Steamflood Performance in Shallow Heavy Oil Reservoirs
Authors: Sarkar A. K. , Sarathi P. S. , Strycker A. R. , Reid T. R.
Published: December 2007

The benefits of horizontal fractures to steamflood performance of shallow, heavy oil reservoirs are demonstrated through reservoir simulation. Two cases were considered: (1) an unpropped fracture to improve mobility of oil ahead of the steamfront, and (2) a nearly impermeable (cement-slurry-filled) fracture to improve vertical sweep efficiency. Horizontal fracturing in shallow reservoirs (<1,000 ft) has been previously demonstrated.

Reservoir data for the low thickness areas of the Slocum (TX) field were used to evaluate the potential of the unpropped fracture. On initiating steamflooding, the steam was injected above formation parting pressure while the oil production rates remained high. The fracture was introduced at the top of the reservoir (i.e., away from the underlying water zone). Subsequent steam injection pressures were below the fracture reopening pressure. The results were compared to those of steamflooding where pressures were always maintained below the formation parting pressure. Steam soaking the formation with the fracture accelerated the recovery process. For the 2.5-acre pattern, project time decreased by 40%, cumulative oil steam ratio (COSR) increased by 20%, and production cost decreased by 16%. Production costs (per bbl of oil) for formations with and without underlying water zones were $13.80 and $12.30 when produced-water heat and 5-acre patterns were used.

Published data for a thick Kern River (CA) reservoir were used to evaluate the benefit of the impermeable fracture. The fracture was introduced into the reservoir, immediately below the elevation of the steam override zone, after 5.6 years of steamflooding. The steamflooding was simulated to continue in the zone below the fracture for four years, and the results were compared with those of the low-quality steamflood conducted in the field over the same period. Steamflood performance improved significantly. Oil recovery increased by 10% OOIP (30% of no-fracture production), mainly because of higher temperatures and steam saturations in the layers below the fracture.
Nature, Origin, Treatment and Control of Well-Bore Scales in an Active Steamflood, Wilmington Field, California
Authors: Davies D. K. , Vessell R. K. , Fu R. Y. , Mondragon J. J. , Stepp D. A. , Aguey O. J.
Published: December 2007

Three principal families of scale minerals occur in this field, carbonates, sulfates and silicates. The carbonate scale is calcite. It is chemically and mineralogically complex owing to variable substitution of Mg for Ca in the crystal lattice. Four varieties of calcite are differentiated on the basis of Mg:Ca ratios. The amount of Mg increases with decreasing temperature. Carbonate scale is precipitated at higher temperatures than sulfate and silicate scale.

Ions that form the carbonate and sulfate scales originate from formation waters. Scales that result from interactions of hot fluid with the formation (silicates) are not volumetrically significant. Long-term prevention of scale precipitation should focus on chemical treatment of fluids and reduction of well bore temperature.
Geostatistical Reservoir Characterization Using Inverted Seismic Data: Application to a Chalk Reservoir, Dan Field, Denmark
Authors: Vejbaek O.V. , Rasmussen K.B.
Published: December 2007

Seismic impedances calculated from logs show very good correlation to log porosities in wells penetrating the chalk reservoir in the Dan Field, Danish North Sea. This is the basis for an attempt to use seismic impedances derived from inversion as soft data for geostatistical reservoir characterization. The study focuses on porosity description of the Maastrichtian chalk reservoir unit, laterally restricted to an area covered by a subset of a 3D seismic survey. This seismic volume was inverted using the ISIS software producing a volume of seismic impedances.

Spatial porosity realisations are produced using a gaussian collocated cosimulation algorithm, where well log porosities constitute the hard data input and seismic impedances are the soft data input. The simulated volume measures 1400-1525 102 m and is oriented parallel to lines and crosslines in the seismic data set. Simulated blocks measures 25 25 6 m equivalent to twice the line and trace spacing, and approximating the seismic sample rate. The correlation coefficient between log porosities and impedances calculated from logs alone are shown to be misleading since they suggest unrealistic high coefficients. However, the inversion derived impedances and log porosities, still show correlation coefficients in the order of -0.45; sufficient to make the inversion result useful. It is remarkable that the calculated correlation coefficient is based on 15 wells, and the inversion is based on only one well. The impedances show inverse correlation to porosities. The impedance data indicate the level of average porosities at locations between wells. The fine structure is produced by the geostatistic process, with averages constrained by seismic impedances. The inversion derived seismic impedances are thus shown to constitute useful primary data to constrain reservoir characterization between wells.