bluuebunny/crossref_metadata_2025 huggingface dataset:
Economics of Offshore Oil Production
Authors: Kuuskraa Vello A. , Ryan Paul , Muller John M.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

Projections indicate that offshore areas will provide much of the nation's future supply of petroleum. The amount of oil that is ultimately recovered from these areas will be profoundly affected by public policies currently profoundly affected by public policies currently under consideration by the federal government, such as changing oil prices, varying federal leasing policies, investing in research and development, and delaying development.

This study was conducted to examine the effects of these policies on offshore oil production. Previously available models of production. Previously available models of offshore cost models were limited severely for this purpose because they often ignore the important variables to water depth and field size and because they frequently fail to account for the full range of essential costs.

The model developed for this study sought to remedy these shortcomings by incorporating these variables and including all costs. Projections of undiscovered reserves were Projections of undiscovered reserves were distributed by water depth and field size based on the distribution of existing federal offshore fields and onshore fields. These were added to the existing reserves to comprise the full data base. The Gulf of Mexico was chosen for the initial detailed analysis reported here.

This paper presents the detailed models and methods, and displays the sensitivity of offshore production to a range of alternative public policies. public policies

Introduction

As existing petroleum resources dwindle and energy demand rises, the need for new domestic energy supplies becomes more important. Onshore exploration and development, improved oil recovery, and synthetic fuels may provide substantial portions of these new supplies, but offshore oil undoubtedly will be a major contributor.

Offshore oil production already makes a substantial contribution to domestic supply — accounting for about 16 percent of current domestic oil production - and its future role is expected to grow. Though projections vary, recent estimates indicate that the offshore area may provide from 30 to 65 percent of the future domestic oil supply (Table 1).

As shown in Table 1, these estimates of the quantity of future (undiscovered) recoverable offshore oil vary dramatically — from a low of 26 billion to a high of 200 billion bbl.
The Effect of Oil Price Policy on Tertiary Oil Recovery
Authors: Henry James D.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

Recent studies have shown that the potential reserves and rate contributions potential reserves and rate contributions from tertiary oil vary over a wide range. The contribution may be very substantial or quite insignificant. One major variable is oil price. The way in which oil price is applied, i.e., oil price policy, is also very important. If we are to recover significant volumes of tertiary oil in a continued oil-price-controlled environment, the incremental barrels of tertiary oil will require a price or price policy equivalent to at least free market price. Timing is critical because many of the major tertiary prospects are approaching their economic limit.

Introduction

Within the last few years, there has been a considerable amount of discussion concerning the increasing inability of the United States to supply its own energy fuels. A recent study by a task force for the National Petroleum Council included a projection according to which the producing rate projection according to which the producing rate of crude oil from known U. S. reservoirs would drop from the current rate of less than eight million barrels per day to less than three million barrels per day within the next ten years. This is shown in Figure 1. This rate represents the total crude oil production from primary, secondary and existing tertiary projects from all known U. S. reservoirs, excluding the North Slope, and excluding future revisions, extensions, and discoveries.

To arrest and possibly reverse this decline in domestic crude oil production will require a combination of programs, such as accelerated leasing, exploration, and development of offshore areas and frontier areas such as Alaska, as well as aggressive implementation of tertiary recovery to recover more of the oil we have already found.

The object of this paper is to examine the stakes and constraints to faster implementation of tertiary programs. Particular emphasis is given to the effect of domestic oil price policy, as set out in current FEA regulations.

TERTIARY POTENTIAL

Conventional primary and secondary recovery processes still leave approximately two thirds of the oil that is found in the ground.
Conversions to Electric Power Change Trends in Energy Demand
Authors: Larson Charles A.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

The total demand for energy is expected to increase from 75 Quads in 1975 to 177 Quads in the year 2000. While the growth in total demand is forecast at 3.5 per cent, electric energy growth is forecast at 6.8 per cent, at almost twice the average rate.

Nuclear power, which makes up only two per cent of today's energy sources, is expected per cent of today's energy sources, is expected to constitute about 37 per cent of total energy demand by the year 2000. In the electric utility industry about 8 per cent of its energy comes from nuclear sources now. By the year 2000, about 59 per cent of all electric energy might be from nuclear sources.

Conversions to electric energy are most likely in the residential, industrial and transportation sectors. Residential electric heating predominates the space heating market. Industrial predominates the space heating market. Industrial conversions are caused by shortages of natural gas and concern over foreign imports of oil. Also, the industrial market is best able to implement "soft" technologies which conserve energy. Electric cars and expanded electric mass transportation may cause conversions in the transportation sector.

CONVERSIONS TO ELECTRIC POWER CHANGE TRENDS IN ENERGY DEMAND

What changes are taking place in the demand for energy? What is causing the conversions to electric power? What are the consequential effects of energy conversions on the oil and gas industry? These and other important questions can best be answered by analyzing a 25-year energy model which describes and explains changing trends in energy demand.

The Energy Model

It appears advisable to look forward over a 25-year period to the year 2000 in order to examine some marked changes in the energy picture. Consequently, a 25-year energy model picture. Consequently, a 25-year energy model was constructed which shows changes in the sources and uses of energy. The trend in total energy demand compared with the trend in electric energy demand is shown on Fig. 1. During 1975 the total normal energy demand was approximately 75 Quads (10 15 Btu's) after adjustment for abnormal weather conditions.
The Outlook for Western Coal in the Competitive Marketplace
Authors: Pistole Harry
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

To meet marginal energy requirements of the next 15 or 20 years, the US has only three viable alternatives . . . imported oil, nuclear energy, and coal. Imports are vulnerable to supply interruptions at the hands of foreign governments, and they present balance of payments problems. present balance of payments problems. Nuclear energy continues to face delays from financing, siting, and environmental problems. While increased coal usage also problems. While increased coal usage also faces specific problems, the US has about half the free world's reserves, and it is believed coal will increase its share of total US energy supply from 18% now to 25% in 1990, while oil and gas decline from 74% to 58%. To meet this demand, coal production must more than double by 1990, production must more than double by 1990, even with a three-fold increase in nuclear capacity. Much of the increased coal must come from the West because it is generally lower in sulfur content and less expensive to mine. In this 15-year time frame, western coal production is expected to increase almost six-fold.

Western coal faces all of the usual complexities of large-scale development in a frontier environment. . . limited infrastructure, severe sociological impacts, unfamiliar and uncertain marketing prospects. But in the West, all of the "usual" frontier uncertainties are surpassed by the uncertainties of government . . . legislation, regulation, and litigation. Eighty percent of western coal is directly affected by federal policy. Can leases be secured under federal leasing regulations? Can coal be mined under the various environmental laws? Can coal be used under the Clean Air Act? Can the consumer afford to buy the coal after it has traversed this expensive maze? These are but a few of the uncertainties facing the investor in western coal.

Higher energy prices have made coal more competitive among the viable alternatives for the marginal fuel market, and the economic foundation for significant growth in coal is being formed. Moreover, the added economic stimulus will promote new technology. It is our view that western coal is too important a national resource not to get on with its development during a period when our nation is experiencing a growing shortfall in meeting its energy needs. By the same token, now is not the time to legislate out of the business those investors whose skilled manpower, financial resources, and management capability are ideally suited to the development of coal for direct use as well as the technology for its conversion to synthetic fuels.
A Competitive Bidding Model That Uses Historical Data
Authors: Hartsock James H.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

A mathematical model has been derived and solved to compute the bidding strategy that maximizes the expected present worth in a competitive bidding environment. Basically, the model consists of three modules, each of which is processed sequentially. The first module performs a risk analysis on the geological performs a risk analysis on the geological estimate of the reserves under the lease and passes the expected reserves to the second passes the expected reserves to the second module that computes the expected present worth of these reserves. This value is then passed to the competitive bidding module that computes the bid that maximizes its expected present worth.

The competitive bidding model was developed to compute the probability of winning with a given bid. A Pearsonian analysis was performed on the published results of past lease sales to identify the functional forms of the probability density functions used i-n the model, and regression analyses of past lease sales provided estimates of the model's parameters. In addition, a data base management and maintenance system was coded to update the parameters of the model upon the completion of each lease sale.

The model has been tested in several recent federal lease sales and the results of the model compare favorably with the actual bidding outcomes.

Introduction

In order to achieve the objectives established by Project Independence, the Bureau of Land Management has accelerated the leasing of potential oil and gas acreage in the federal offshore areas. Since competitive bid leasing began 22 years ago, a total of approximately 18 million acres have been leased, 30 percent of which have been leased in the past 4 years. This increased activity has posed several interesting problems for management when developing a strategy for bidding. For example, is it more beneficial for a company to bid with a group, thereby spreading the risk by reducing the expected cost, or should a company bid alone and assume the full risk? With few exceptions, recent bidding results imply that corporations are unwilling to assume the full risk. Should a bidding combine spend their leasing budget by bidding very high on a few low-risk tracts, thus enhancing their chances of winning some tracts, or should they distribute the budget over more tracts by bidding less on each tract while reducing the chances of winning any single tract?
Morrow Stimulation in Southeast New Mexico
Authors: Simon David E. , Underwood Porter
Published: December 2007

The purpose of this paper is to reevaluate the stimulation procedures used in the Morrow Sand formation of Southeast New Mexico, and to improve these techniques based on current and new information.

This study considers the geological aspects of the Morrow Sand using the scanning electron microscope to investigate each Morrow rock type to determine rock properties and composition. The use of DST information is employed to establish pre-stimulation conditions involving transmissibility, BHP, damage ratio and productivity.

A study of fracturing fluids is presented investigating adsorption, clay presented investigating adsorption, clay swelling, compatibility and regained permeabilities with various Morrow rock permeabilities with various Morrow rock types. Fracturing techniques are evaluated using reservoir, DST, log, and fluid data to compare sand placement with thin and viscous fluids, sand concentrations, fracture length, fracture length and stabilized production increases. production increases. Conclusions based on previous work and this study indicate fracture stimulation with viscous gels improves Morrow Sand production.

Introduction

Prior to the late 1960's, the only morrow production in Southeast New Mexico was from wells having sufficient permeability to be completed naturally. permeability to be completed naturally. Stimulation attempts during this period utilized oil-base fluids or saturated brines with little or no increase in production. The first successful production. The first successful stimulation treatments consisted of aqueous potassium chloride solutions gelled with potassium chloride solutions gelled with guar, buffered for low pH, and incorporated a surfactant for low surface tension. The proppant used in these treatments was 20–40 mesh sand and 20–40 mesh glass beads.

In the early 1970's, use of a viscous crosslinked gel system and large sand concentrations proved successful for penetrating through wellbore damage. A typical treatment was 10,000 gallons of crosslinked guar carrying 18,000 pounds 20–40 mesh sand at 10 BPM. pounds 20–40 mesh sand at 10 BPM.
Successful Application of Foam Frac to Shallow Gas Sands
Authors: Ballard John L.
Published: December 2007

The purpose of this paper is not to review previous papers and reports on foam fracturing, but rather to relate and review the job procedures and results of foam fracturing treatments in low bottom hole pressure reservoirs in shallow gas sands. pressure reservoirs in shallow gas sands. This paper covers the mechanical hookup, computer programs relating to job design, sand concentrations obtainable, foaming agents and their concentrations, and a system of accurately monitoring foam quality down stream.

Conventional equipment can be used to provide up to 2 pounds sand per gallon of provide up to 2 pounds sand per gallon of foam, without viscosifying the water. Also, a differential density measuring system is available for monitoring foam quality as it enters the well.

The basic downhole problems solved by this technique are those of fluid retention and formation damage by water-base fluids in these water sensitive and low pressure formations.

Introduction

Foam fracturing has survived a slow beginning and, because of its present success, has become an established technique for stimulating production from gas wells.

The properties and rheology of foam have been discussed by many authors and will not be elaborated on any further.

This type treatment has shown to be more effective in gas wells than oil wells. This is largely due to the fact the liquid hydrocarbons have a tendency to break the foam prematurely, and high concentrations of prematurely, and high concentrations of foaming agents tend to cause emulsion problems. Therefore, the two problems cause a "stalemate." In some reservoirs one chemical can be found to foam effectively at low concentrations without causing emulsions, and in some reservoirs small amounts of a demulsifier can be combined with a nonionic foaming agent.

Many changes have been made in the treatment design in order to more accurately perform the treatment. perform the treatment.
Case History: A Pressure Core Hole
Authors: Bilhartz H.L.
Published: December 2007

A core hole was needed in the Willard Unit, Wasson Field, CO2 Pilot Test in order to evaluate the effectiveness of CO2 flooding. The coring program was designed to determine the residual oil saturation behind the CO2 front and the waterflood residual oil saturation in zones not yet affected by CO2. For the most definitive interpretation of the oil saturations found in the core, the presence of CO2 needed to be associated with the lowest oil saturations. Saturation measurements on conventional cores may result in incorrect values for one or both of two primary reasons:some hydrocarbon may be stripped from the coring by mud filtrate invasion,and additional fluids may be driven from the core by gas expansion as the pressure is reduced during surfacing.

If flushing by mud filtrate is controlled then valid fluid saturations can be obtained using a pressure retaining core barrel to prevent loss of fluids by gas expansion. Furthermore, if gas saturation and/or composition is desirable, then pressure coring is necessary and this was the situation at Willard. However, a major disadvantage to pressure coring is its high cost and a rather low 60% historical success ratio of getting core to surface under pressure.

This paper summarizes the work done with the pressure core barrels prior to spudding in order to increase our chances of getting core to surface under pressure. It also outlines the field procedures which were followed that resulted in obtaining 18 pressure cores out of 19 attempts. Also, discussed in this paper are the core analysis techniques which were used to determine oil, water, and gas saturations at reservoir conditions for full diameter cores.

Discussion

A pilot test of tertiary oil recovery by CO2/water miscible displacement was conducted in the Willard Unit, Wasson Field, Yoakum County, Texas. The Willard Unit pilot consisted of one injection well (32A), one logging observation well (32AO) located 100 feet to the north of the injector, and one fluid sampling and pressure monitoring well (32AS) 25 feet north of the logging well (refer to Figure 1). The test was designed to study unit displacement efficiency and in situ fluid movement and was not a producing pilot test.

The reservoir is a typical West Texas San Andres dolomite with a gross pay interval of 160 feet in the pilot area.
Waterflood Residual Oil Saturation - The Buffalo Field, Timor Sea
Authors: Behrenbruch Peter
Published: December 2007

A representative description of residual oil saturation is one of the fundamental requirements for studying the behaviour of a field under waterflooding.

Presented is a case history for describing waterflood residual oil saturation for the Buffalo field, offshore Australia. The aim is to give a practical framework for correlating laboratory results for residual oil saturation. The new methodology correlates residual oil saturation for a particular facies with initial oil saturation, permeability and when appropriate also wettability, and as a function of displacement velocity. As a non-conventional feature, the wettability parameter used is based on relative permeability endpoints.

It is demonstrated that correlation with permeability can follow both, a more conventional, positive relationship in case of a heterogeneous pore structure and a negative relationship in case of a more homogeneous formation. It is also shown how alteration in wettability, both in-situ due to drilling mud contamination and in the laboratory due to variation in ageing can impact the results.

The strength of the methodology is that it can be applied to very diverse situations and simple nomograms have been developed to better visualise the results. The methodology builds on the ideas of Land1 and can be universally applied using basic, readily available data. The method is also very suitable for comparative studies of different facies of the same field or in comparing different fields. Additional examples are cited from the Gulf of Mexico to demonstrate the applicability of the method.
20 Years of Laboratory Oil-Water Relative Permeability Data in the Malay Basin
Authors: Coyne Patrick L. , Omar Mohd. Ismail
Published: December 2007

The Malay Basin oil reservoirs are typically near shore marine sandstones, many of which are produced via natural water drive or water injection1-3. Esso Production Malaysia Inc. (EPMI) and PETRONAS Carigali Sdn Bhd (PCSB) currently operate 17 oil fields offshore peninsular Malaysia.

Beginning in 1975 and continuing to the present time, EPMI and PCSB have acquired more than 160 sets of laboratory oil-water imbibition relative permeability data to use in predicting field performance. These data were measured on cores cut with a variety of drilling muds, using extracted, restored state and preserved core samples. The relative permeability values were obtained from both centrifuge and waterflood experiments. Each oil-water relative permeability data set was analyzed and Corey equations were used to fit the oil and water relative permeability measurements.

After analyzing all the experimental results, a set of recommended oil-water imbibition relative permeability experiments was selected. Many of the samples were excluded due to the use of less desirable laboratory procedures or coring muds.

Additionally, recommended laboratory relative permeability curves were compared to values derived from simulation history matching. In general, oil relative permeabilities are similar. However, the laboratory curves predict higher water mobilities than the values derived from history matching. Finally, recommended procedures were developed for measuring oil-water imbibition relative permeabilities for future laboratory studies.

The work described in this paper provides a process for analyzing and assessing relative permeability data. The data itself can be used as analogues for similar sandstone reservoirs. In addition, the recommended laboratory procedures can be used to help design special core analysis programs.
Material Balance Study of Gas Reservoirs by Flowing Well Method: A Case Study of Bakhrabad Gas Field
Authors: Choudhury Z. , Gomes E.
Published: December 2007

Due to critical production-demand situation, proper pressure survey can not be conducted on a regular basis in the gas fields of Bangladesh. Shutting in the wells for pressure survey is also very expensive for the gas production companies. Flowing well method provides an opportunity for updating the reserves without interrupting the production. In recent years, pressures of different sands of Bakhrabad Gas Field have been declining sharply and it is believed that the field would be exhausted very shortly. Therefore, Bakhrabad Gas Field is a perfect candidate for applying this new method to estimate the gas reserve and verify it by the actual reservoir performance. Flowing well method of estimating the gas reserve is based on the assumptions that the wells have produced long enough to reach the pseudosteady state condition and the produced gas is relatively dry so that there is no liquid buildup in the well. In this study, actual flowing pressures of the four producing wells of the J Sand of Bakhrabad Gas Field have been analyzed in a similar fashion as the average reservoir pressure in a conventional material balance study. Both wellbore and wellhead flowing pressures have been used to find the reserve. Analytical justifications have been provided in support of this method. Limitations are also explained when applied to a particular gas reservoir. The flowing well method does not require shutting in the wells and conducting a pressure survey. The results of this study have been compared with those of conventional material balance and simulation studies. The results have also been compared with those of other studies previously conducted on Bakhrabad Gas Field. These comparisons show that the gas in place values obtained from flowing well method compare well with those of other studies.
Chemical Evolution of Formation Waters in the Palm Valley Gas Field, Northern Territory: Impact on Field Management
Authors: Andrew A. S. , Whitford D. J. , Berry M. D. , Giblin A. M.
Published: December 2007

The chemical composition and evolution of formation waters associated with gas production in the Palm Valley field, Northern Territory, has important implications for reservoir management, saline water disposal, and gas reserve calculations. Historically, the occurrence of saline formation water in gas fields has been the subject of considerable debate. At Palm Valley gas field there were no occurrences of mobile water early in the development of the field and, only after the gas production had reduced the reservoir pressure, was saline formation water produced. Initially this was in small quantities but has increased dramatically with time, particularly after the installation of compression in November 1996.

Produced waters from the field have been chemically and isotopically characterized in order to investigate the origin of the extreme salinity observed in some cases. The produced waters range from highly saline (TDS=>300,000), with unusual enrichments in Ca, Ba and Sr, to very low salinity fluids that may represent condensate waters. The Sr isotopic compositions of the waters are also variable but do not correlate closely with major and trace element abundances.

The formation waters preserve chemical and isotopic heterogeneities and are thus not well mixed. The high salinity brines have Sr isotopic compositions and other geochemical characteristics more consistent with long term residence within the reservoir rocks than with present-day derivation from a more distal pool of brines associated with underlying evaporites. This conclusion is important in that the brines, if locally derived, may be less significant volumetrically than might be expected if there was present-day hydrological continuity between the brines and the evaporites.
Analysis on the Depletion and Recovery Behavior of a Geopressured/Geothermal Reservoir
Authors: Lee K. S.
Published: December 2007

Geopressured-geothermal reservoirs are presumed to contain a large resource of natural gas in solution with the native brine. The Gladys McCall geopressured-geothermal reservoir is one of such aquifer monitored and tested under U.S. Department of Energy geopressured-geothermal research program. Transient pressure analysis techniques were used to evaluate the performance of the reservoir. Analysis of transient pressure data furnished a specific reservoir description such as the formation parameters, pore volume and shape of the reservoir, and average reservoir pressure. Results of pressure tests suggest that the Gladys McCall reservoir probably has a long narrow shape with the well located significantly off-center. During both production and shut-in periods, pressure buildup tests provided some evidence of external pressure support. Aquifer recharging from a leaky boundary was believed to be the main source. An aquifer influx model was derived from a conceptual model of water leakage through a partially sealing fault into the reservoir under steady-state conditions. The model has been employed to match the production history of the test well. A match of the pressure history required that the conductivity of the fault be a function of the pressure difference between the supporting aquifer and the reservoir. Results of analyses provided a quantitative evaluation of the reservoir and a better understanding of the reservoir energy drive mechanism.
Plus Fraction Characterization and PVT Data Regression for Reservoir Fluids near Critical Conditions
Authors: Zuo Julian Y. , Zhang Dan
Published: December 2007

PVT information of reservoir fluids is of great importance to reservoir engineers. In order to describe phase behavior and PVT properties using equations of state (EOS), a characterization procedure is required for true boiling point (TBP) and plus fractions of reservoir fluids. Although reasonable prediction accuracy can be obtained, the EOS parameters need to be tuned to improve the agreement between the measured properties and the calculated results.

In this work, several characterization methods have briefly been reviewed and the results of two widely used characterization procedures have been compared with the experimental data. The characterization methods can be applied to both single and multiple sample systems. For single sample systems, either an exponential or a three-parameter gamma distribution function was used to split the plus fraction into subfractions. Then the TBP fractions and split subfractions were lumped into groups (pseudo-components) by means of molar averaging, mass averaging, Qauss-Laguerre quadrature or arbitrary selection. For multiple sample systems, a method has been developed to generate the same number of pseudo-components for each sample and the same physical properties of each pseudo-component while the mole fractions of pseudo-components reflect the overall distribution of C7+ mixtures.

In addition, a regression technique has been developed to fit the PVT data and phase behavior for single or multiple samples of reservoir fluids. A modified Levenberg-Marquardt nonlinear least-square algorithm has been utilized in this work. A sensitivity analysis is performed to determine which parameters are more sensitive. The more sensitive parameters are then chosen as adjustable parameters to fit the experimental PVT data. The lower and upper bounds can be set for each adjustable parameter. Finally, regressions are performed to match the measured saturation pressure, volumetric and viscosity data of reservoir fluids separately or simultaneously.

The developed characterization and regression techniques have been tested for oils and gas condensates near critical conditions and under ordinary conditions as well as for multiple samples that taken from a reservoir with a strongly compositional gradient. The results show that the implemented methods provide a reliable and efficient tool for representing PVT properties and phase behavior of reservoir fluids.
An Experimental and Theoretical Investigation of Upward Two-Phase Flow in Annuli
Authors: Lage Antonio C. V. M. , Time Rune W.
Published: December 2007

A mechanistic model is formulated to predict the mixture behavior for upward two-phase flow in concentric annulus. The model is composed of a procedure for flow pattern prediction and a set of independent mechanistic models for calculating gas fraction and pressure drop in bubble, dispersed bubble, slug and annular flow. In addition, some aspects of churn flow such as the slug/churn transition and the predictions of pressure drop are discussed.

A comprehensive experimental program was also launched to collect data. An extensive full-scale investigation was executed in a 1278 m vertical well with an 88.9 mm x 159.4 mm (3.5 in. x 6.276 in.) annulus. The test matrix covered the whole range of possible combinations of liquid and gas injection rates for an UBD operation in a similar geometry. Small-scale tests were also performed in a U-tube, which simulates the simultaneous injection of liquid and gas through the drill string. The U-tube apparatus comprehended a descending pipe (ID=34 mm=1.34 in.) and a 41 mm x 74 mm (1.61 in. x 2.91 in.) ascending annulus. Small-scale data available in the literature were also collected and catalogued.

The model is validated against the acquired database and shows a good performance for pressure drop prediction. Further, the performance of the model is also compared with other multiphase empirical or mechanistic models from the literature. The proposed model performs better than the other alternatives.
Infill Drilling in the Mississippi Limestone, Garfield County, Oklahoma
Authors: Maddox Gaiser D.
Published: December 2007

Development drilling of the Mississippi Limestone in southwestern Garfield County, Oklahoma, took place in the mid-1960's. Most of the development was either one well per quarter-section or one well per section, depending on the predominance of oil or gas in the hydrocarbon production.

In 1972, Union Texas Petroleum Division, Allied Chemical Corporation, drilled a second well on one of the quarter-sections to test the adequacy of the drainage by the original well. Results indicated that additional development was justified, and numerous new wells have been drilled since that time by Union Texas and by other operators as well. Drilling problems, completion techniques and some of the problems, completion techniques and some of the results obtained are discussed.

Introduction

The Mississippi Limestone is a massive fractured limestone underlying a large part of northwestern Oklahoma. It has been found productive of hydrocarbons in varying degrees productive of hydrocarbons in varying degrees over much of an area stretching from 12 miles east of Enid to 40 miles west and from 12 miles north to 15 miles south, give or take a few miles in any direction.

The specific part of this area to be discussed is north and west of the town of Waukomis, mostly in Township 21 North, Range 7 West. Most of this township had been developed in the mid-1960's with only one well per quarter-section, thought at the time to per quarter-section, thought at the time to be sufficient to recover the hydrocarbons which were economically recoverable. Some of the sections in the northern part of T21N and all of those in T22N had only one well per section, because they had been predominantly gas productive when completed. In 1972 the Exploration Department of Union Texas Petroleum prepared several maps contoured on Petroleum prepared several maps contoured on cumulative oil production through June 1971. The map of the Waukomis area indicated that the wells in T21N, R7W had recovered significantly more oil than in other areas, as shown in Figure 1.

The Mississippi Limestone has very low porosity, generally in the 3 - 6% range. porosity, generally in the 3 - 6% range. At the same time, this porosity is present throughout the entire thickness, which exceeds 500' in most of the wells.
Technology Applied to Extend the Drilling Reach of a Platform Workover Rig
Authors: McNair G. A. , Cassidy S. D. , Zheng Z.
Published: December 2007

The term "Extended Reach Drilling" refers to drilling operations conducted beyond the normal reach of drilling facilities. Typical problems associated with this type of operation are torque & drag limitations, wellbore stability, mud rheology and solids control and directional well design1,2,3. Such problems are particularly challenging to the CACT Operators Group due to limited platform rig size and platform deck space. These problems are further compounded by the fact that no spare well slots are available on the platforms, so all new platform drilling operations are sidetracks. This results in tortuous 3-dimensional well profiles that generate high levels of drilling torque and drag, disproportionate to the measured depth. The well planning and drilling practices used to drill these wells are very similar to those used in ultra-long extended reach wells and reflect the challenging nature of platform sidetrack operations.

This paper describes the challenges that are faced during development of the well plans and details the methods that are later used while drilling the sidetrack wells. Case histories with actual field data will show how the applications of the following new or emerging technologies have been applied successfully in the sidetrack program.

Borehole Stability Modeling was used to identify areas where the potential for borehole breakout and fluid losses (lost circulation) existed, so that plans could be made to avoid these problems. Real Time Downhole Data Measurements were used to provide instantaneous information on drilling conditions in order to avoid the problems experienced in previous wells. PDC bit designs, featuring low torque cutting structures to improve bit steerability were successfully applied on several recent sidetrack wells.
Effect of Mobile Oil on Residual Oil Saturation Measurement by Interwell Tracing Method
Authors: Tang Joseph S , Zhang Pei-Xin
Published: December 2007

Interwell tracing has been recognized as a reliable method for determining residual oil saturation between wells. Sponsored by the United Nations International Atomic Energy Agency, China Institute of Atomic Energy is currently conducting several tests in various China oil fields to determine residual oil saturation and to delineate reservoir problems. Interwell method assumes tracers contacting immobile oil in the watered-out zone and the oil saturation is calculated from the partitioning tracer propagation rate. In the presence of mobile oil, the partitioning tracer velocity would increase as it can contact, partition into and move with the flowing oil. As a result, assuming zero oil rate would lead to underestimate of oil saturation.

In an unsteady state displacement where tracers are injected with water into a virgin reservoir, the partitioning tracer will move with oil at a constant characteristic velocity governed by the partition coefficient. Since tracers are normally injected after the start of waterflood, the injected tracers will lag behind their respective characteristic fronts. The time required for the partitioning tracer to catch up with its characteristic front and the breakthrough time of the tracer in a pseudo 1-D system were theoretically analyzed in this paper. The produced oil cut, which is dominated by streamline distribution, sweep and layering, is not a definite indicator of mobile oil in the water zone. The presence of moving oil and its effect on oil saturation measurement can be inferred from the responses of two tracers with different partition coefficients.
Roundly Carry Out HSE Managed System Strengthen Construction of Enterprise Culture
Authors: Bo Zhang
Published: December 2007

This article began with the construction of enterprise culture.

It briefly introduced the contents of HSE management system. It further expaunded that the core of HSE management system was to produce the products and service, which fit for HSE, and about how to change the old management methods, how to operate HSE management system, how to strengthen the training of HSE adminstrative personels, and so on. Finally, the article indicated HSE management system was the cornerstone to establish the enterprise culture and the key to set up the favorable enterprise culture.
Oil and Gas Production and Environment Protection
Authors: Li Jin , Li Binyuan , Wang Chengwu , Chen Dajun
Published: December 2007

Oil and gas production cost keeps increasing because of going-up of water cut, going-down of oil connect, difficulty and expensive cost of treating polluted water. It is true especially for treating and discharging polluted water in Sichuan gas filed. Generally, oil and gas production procedures include producing oil of gas combined with water, separating oil or gas from water on surface, treating polluted water, and rejecting polluted water. The cost of treating polluted water is up to ¥20–30RMB/m3. The output of water on average is 60–80 m3/day and 200 m3/day maximally in the Northwest gas field of SPA. The cost of treating polluted water is about 30% of production cost, treat polluted water environment is the top goal for oil and gas company to pursuit. It is necessary to employ underneath close loop producing technology that oil or gas is separated underneath, polluted water is rejected, oil or gas is diverted on surface. The technology may in crease oil and gas production by 20–25%, due to increase of producing pressure drawdown, and reduce production cost by 50% because of improving working conditions of facilities, the cost of treating polluted water reduces by 50–60% and the pollution of water is avoided efficiently by employing new-type dual flow channel spiral separator.
Modeling Wellbore Dynamics During Oil Well Blowout
Authors: Hasan A. R. , Kabir C. S. , Lin D.
Published: December 2007

Blowout or uncontrolled flow of an oil well involves complex flow phenomenon involving transient multiphase flow and heat transfer in the wellbore. Various wellbore and reservoir parameters govern the maximum velocity attained in a given well. The maximum velocity may be either critical (sonic) or subcritical. This work adapts a transient model to capture the events leading to the onset of maximum velocity of a fluid mixture. The model uses a numeric method to solve the mass, momentum, and energy equations for the wellbore, and an analytic approach for fluid flow in the reservoir.

The theoretical sonic velocity computed by assuming isentropic expansion turns out to be higher than the actual maximum velocity attainable in the well. Computational results also show that the assumption of isentropic expansion becomes progressively worse with increases in gas/oil ratio, because of increased frictional loss. Among various parameters, the blowout rate increases with increased well-productivity index, flow-string diameter, reservoir pressure, and gas-oil ratio (GOR). The probabilistic reservoir-simulation approach is used to answer the reservoir-fluid–loss question.
Simplified Shaly Sand Analysis
Authors: Fertl Walter H. , Watt Harold B.
Published: December 2007

A simplified shaly sand analysis that uses a resistivity-one porosity log combination is discussed. The method involves estimation of shaliness by conventional techniques and, if necessary, porosity corrections for gas effects. A "pseudo-q" factor, which compares favorably with q-values from the Density-Acoustic combination, provides a basis for determining cutoff permeability. Computed water saturations compare well with the conventional Swq-equation.

The new method is applicable to minimum logging combinations as frequently run in development wells.

Introduction

Log analysis of shaly pay sands has received considerable attention. In many investigations, the clays and fluids occupying the interstices of the sand matrix are treated as a slurry, and the effect of both clay and hydrocarbons is taken into account. Based upon the dispersed clay model, the formation water saturation (Swq) has been estimated successfully in the U.S. Gulf Coast area for many years.

Resistivity of the disseminated clay (Rc)is not exactly constant. However, an average value should be useable for a given geological area, since under most circumstances even relatively large changes in the value of Rc cause only small variations in the computed water saturation. Generally, the resistivity of clays dispersed in the pore space of a reservoir rock is less than that of adjacent shales. Values of Rc = 0.5 Rsh for the shallow Wilcox of Louisiana and Mississippi have been given. For the Gulf Coast we recommend the use of Rc = 0.4 Rsh, which closely agrees with the concept of multiple Rw-values proposed previously. previously.

BASIC CONSIDERATIONS

Considering the response of porosity tools, such as the Density and Acoustic, to the shaliness of a formation, it is possible to compute water saturation, with one porosity tool only. In addition, it is then possible to derive a pseudo-q value, which gives an indication for the amount of clay in the formation and, therefore, estimates the likelihood for reservoir producibility. Response of Density and Acoustic logs in shaly, water bearing sands can be expressed such as:

..........Density........(1)
Fast Method for Real-Time Interpretation of Variable-Rate Wells with Changing Skin: Application to Matrix Acidizing
Authors: Ma L. , Johns R. T. , Zhu D. , Hill A. D.
Published: December 2007

Conventional well test analyses typically assume that the wellbore skin factor is constant over the entire duration of the well test. For certain cases such as during acidizing treatments, however, the skin factor can change significantly and affect the pressure response. The concept of well test analysis has been used in real-time evaluation of well stimulation treatments. Numerical and analytical methods have been developed to estimate the evolution of skin during acidizing, but these methods can be time consuming and cumbersome when numerous pressure and rate data exist.

In this paper, we apply the flow rate normalization method used in well testing to estimate skin as a function of time. We demonstrate that the new technique is accurate, robust, fast, and easy to use. We apply the method to two matrix acidizing treatments performed in a water well and an oil well. The skin calculations for each example agree well with those calculated from current accepted methods. The new technique is a fast, simple and more accurate method for real-time interpretation of acidizing treatments where a multitude of pressure and flow rate data exists. We compare the results from the new method to current methods for several field examples.
The Artificial Neural Network Method of Well-Test Interpretation Model Identification and Parameter Estimation
Authors: Deng Yuanzhong , Chen Qinlei , Wang Jiahong
Published: December 2007

A correct well-test interpretation model is the basement of well-test analysis, which is identified by the feature of pressure derivative curves. Automatic identification of well-test interpretation model is very important for automatic parameter estimation from the well test data. Based on the excellent performance of classification and the feature of noise insensitive, the artificial neural network (ANN) has been studied extensively in identification of well-test interpretation model. Whether the trained ANN can identify the interpretation model of the actual tested curve correctly depends on the ANN construction method. Using the derivative curve's data point series as input vector to train ANN can't ensure the actual tested curve in the same model area as it training samples. So the sample curves data point series trained ANN usually misidentify the interpretation model of the actual tested curve. Based on the pressure derivative curve's common features among different interpretation models, an ANN approach is proposed to realize the type curves matching and move the tested curves to its sample position. Using curve's binary numbers instead of data points as input vector to train ANN can guarantee the actual tested curve in the same model area as its training samples, this ensure the successfully trained ANN can identify the interpretation model of the actual tested curve correctly. The examples showing that the proposed method is more efficiently than the data point series method. In the process of interpretation model identification, the parameters can also be estimated.