bluuebunny/crossref_metadata_2025 huggingface dataset:
Preliminary Evaluation of Rock Springs Site 9 In-Situ Oil Shale Retorting Experiment
Authors: Wise R.L. , Sudduth B.C. , Winter J.M. , Jackson L.M. , Long A.
Published: December 2007

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

Successful startup of an in situ retorting experiment in the Tipton Member of the Green River oil shale formation near Rock Springs, Wy. began on April 5, 1976, at Rock Springs site 9. The target shale was located in a 40-foot zone between 137 and 177 feet beneath the surface and averaged 21.3 gallons of oil per ton and 2.3 per cent water by Fischer assay. After fracturing the shale zone with a combination of hydraulic and explosive fracturing treatments, the oil shale was ignited at a central air injection well with an electric heater and a propane burner. The oil shale was retorted in advance of the combustion front which propagated radially toward eight surrounding production wells. About 700 gallons of oil and 165 MM Btu of low-Btu gas were recovered during the first 35 1/2 days of operation.

Preliminary evaluation indicates that only a fraction of the oil shale reserves were retorted in advance of the combustion front. A computer data acquisition system automatically monitored underground temperatures, pressures, gas flow rates, and gas compositions at hourly intervals. Based on integration of these measurements, energy and material balance calculations indicate that the maximum amount of shale retorted in specially designated test areas was probably less than 14 to 18 percent of the oil probably less than 14 to 18 percent of the oil shale reserves within the 40-foot zone.

Post-retorting core samples will be evaluated after the experiment is finished. At the time this paper was prepared, the experiment was still continuing and data from only the first 35 1/2 days of operation were available. When the experiment is completed, data from environmental monitoring of the experiment will also be evaluated to determine the impact of in situ oil shale processing on air, water, and land quality. processing on air, water, and land quality

Introduction

Development of the oil shale resources in Colorado, Utah, and Wyoming could contribute significantly to the goal of achieving national energy independence. So far, the primary efforts to develop these resources have emphasized a combination of mining and surface retorting. However, two-thirds of the "potentially recoverable" shale oil resource is in low-grade deposits that may never be recovered by conventional mining techniques.
Oil Yield and Quality from Simulated In-Situ Retorting of Green River Oil Shale
Authors: Needham R.B. , Judzis Arvids , Cornelius A.J.
Published: December 2007

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

The yield and quality of shale oil produced for in-situ retorting conditions was measured by laboratory experiments and related to shale particle size, retorting temperature, and particle size, retorting temperature, and heating rate. In-situ retorting with recycle shale gas at a temperature of 800 deg. F should result in an oil yield of 80 to 85 weight percent of Fischer assay. The in-situ retorted percent of Fischer assay. The in-situ retorted oil would contain 1.7 to 2.0 weight percent nitrogen and 0.5 to 0.7 weight percent sulfur; these values are typical of shale oil from the conventional gas combustion retort. The in-situ retorted oil will have a slightly higher API gravity and be more volatile than oil produced by the gas combustion retort because of additional thermal cracking during production from the larger particles. The oil yield and nitrogen content of the oil did not depend upon the shale particle size for retorting temperatures up to about 800 deg. F, but at higher retorting temperatures, the oil yield was markedly lower for the larger particles. Therefore, in-situ retorting temperatures should be less than about 800 deg. F.

Introduction

This laboratory investigation of the oil yield and quality obtained from Green River oil shale simulated the conditions for the indirect heating method of modified in-situ retorting. In this method an underground retort is created by fragmenting an oil-shale bed in-situ and thereafter the bed is heated by the injection of hot shale gases. Methods of creating in-situ retorts by fragmentation of shale beds have been considered and experimental fragmentations are being conducted. Most of the reported investigations on retorting methods to recover the shale oil from such fragmented shale beds have concentrated on the in-situ combustion method.

The information obtained in this work specifically applies to the modified in-situ retorting process where a fragmented shale bed is heated by injecting hot shale gases into the top of the fragmented zone. The cooled gases and oil are considered to be recovered at the bottom of the fragmented zone. The conditions anticipated for such a process requires that lower retorting temperatures, longer times, and larger shale particles be used in the simulation than is usual for conventional surface retorting processes. processes.
Test Of A Submerged Production System - Progress Report
Authors: Childers T.W. , Loth W.D.
Published: December 2007

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

Offshore installation of Exxon's prototype Submerged Production System is prototype Submerged Production System is nearing completion. This pilot test installation is being conducted in Exxon's West Delta 73 Field in the Gulf of Mexico. It includes the equipment necessary to develop and produce deep water oil reserves. This pilot test should provide the information necessary to verify provide the information necessary to verify equipment designs, as well as deep water installation, operating, and maintenance procedures. The program thus far has procedures. The program thus far has included the seafloor installation of two large pile-founded structures (a drilling and production template and a marine production riser base), installation of two production riser base), installation of two subsea booster pumps on the template, and drilling and completion of three directional wells which have been connected to the subsea manifold. All five pipelines and the two electric cables required have been laid and connected to establish necessary communications between the template, riser base, and surface production facilities located on a nearby platform. Finally, remote maintenance procedures and tools have been used to perform maintenance tasks on the subsea equipment. The system is currently being brought up to operational status.

While most of the equipment and procedures have proven satisfactory, numerous procedures have proven satisfactory, numerous unexpected problems have been encountered. These have been solved using techniques applicable to deep water operations. Improvements are needed in some areas to reduce installation costs and increase equipment performance. Our experience to date continues to generate confidence that deep water oil reserves are within reach of current technology and the problems attendant with the use of complex equipment in a remote environment can be satisfactorily overcome.

Introduction

This paper updates progress of the offshore activities of the SPS pilot installation. Previous papers described the system in detail and discussed the fabrication of a prototype system and its offshore installation in Exxon's West Delta Block 73 Field in the Gulf of Mexico.

To facilitate the review of this paper by readers who do not have access to the previous papers, elements of the SPS and previous papers, elements of the SPS and the pilot test installation are briefly described in the following paragraph.
Analysis of Pressure Buildup in an Infinite Two-Layered Oil Reservoir Without Crossflow
Authors: Otuomagie Robert , Menzie D.E.
Published: December 2007

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

The purpose of this study is to obtain a set of expressions and procedures that can be used to determine the reservoir parameters from pressure buildup curves for an infinite pressure buildup curves for an infinite two-layered oil reservoir. Equations were derived that define the pressure behavior at the wellbore. Pressure drop equations were derived for the upper and lower zones using Hartsock's method. From these pressure drop equations, other equations were derived that describe theoretical buildup for this system when the well is shut in.

From these equations it is possible to determine the initial pressure of one zone the other initial pressure or the difference between the two initial pressures of the respective zones are known. The effective permeabilities can also be computed under the permeabilities can also be computed under the above conditions; that is, if the initial pressure in either zone is known or if the pressure in either zone is known or if the difference in pressure between the two zones is known.

Hartsock used only the pressure drop of the upper zone for these derivations and determinations, but this study shows that from the pressure drop and shut-in pressure equations, equations can be derived to determine the skin factors for the upper and lower zones. This study also shows under what conditions an infinite two-layered oil reservoir is similar to a single-layered reservoir.

Hartsock and Lefkovits et al. methods have been used to show the effects of permeability and thickness ratios on pressure buildup permeability and thickness ratios on pressure buildup curves. Also studied were the effects of skin and wellbore storage using the equations derived for an infinite two-layered reservoir with boundary conditions at the wellbore outlined by Lefkovits et al.

Introduction

The pressure buildup analysis considered in this study is that of an infinite two-layered reservoir without crossflow. So far, equations have not been developed to obtain the pressures, permeabilities and skin factors for the permeabilities and skin factors for the individual zones of two- or more-layered reservoirs.

Lefkovits et al. studied the behavior of bounded reservoirs composed of stratified layers. Their work showed that the time necessary to reach pseudo-steady state is much longer for a two-layer reservoir than for a single-layer reservoir.
A Unified Treatment of the Effects of Wellbore Storage and Variable Sandface Flowrate on Gas Well Drawdown and Buildup Analysis
Authors: Breit V.S. , Bishop K.A. , Swift G.W.
Published: December 2007

This Paper is Subject to Correction

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

A unified method for analyzing drawdown and buildup data for permeability, non-Darcy coefficient, and skin factor is presented. The method account for wellbore storage and variable sandface flow rate. Drawdown/buildup data for two rates from an experimental reservoir are analyzed with this method. The parameters obtained from that analysis were used in a mathematical reservoir simulator to generate a pressure-time history which matched the experimental history within 3 psi over the test period, thereby demonstrating the compliance of the experimental reservoir with accepted principles of compressible fluid flow in porous principles of compressible fluid flow in porous media.

Introduction

For several years we have been performing drawdown and buildup experiments using an apparatus which is a physical analog of a gas reservoir with a single, centrally located, production well. Although care has been taken to preserve dimensional similarity between our "model" reservoir and a actual reservoir wherever possible, the model necessarily has a larger well storage volume/surface flow rate ratio than its real counterpart because the equipment for measuring pressure and rate, and the valves used on the model apparatus cannot be built to dimensional scale. Also, attempts to control the model reservoir flow rate have been thwarted because of the storage volume associated with the apparatus. Thus, to analyze the model drawdown and buildup data we must take particular care to correct the data for wellbore particular care to correct the data for wellbore storage and variable sandface rate effects and have developed a procedure for doing this. This procedure has utility for reducing field test data procedure has utility for reducing field test data as well as our experimental model data.

A number of papers have treated these effects-those of Ramey and Odeh and Jones cite most of the other relevant papers and present a good theoretical basis for the method presented here. Our paper unifies previous theory—presenting detailed procedures for properly analyzing drawdown and buildup data taken under variable flow rate conditions with appreciable wellbore storage present. The procedures are demonstrated by present. The procedures are demonstrated by applying them to data for two rates acquired from our experimental model. The values obtained for permeability and skin factor from this analysis permeability and skin factor from this analysis are used in a mathematical reservoir simulator to generate pressure-time histories for the experimental sandface rate-time history. Comparison of these computed pressure-time histories with those measured experimentally demonstrate the degree of compliance of the experimental reservoir with accepted principles of compressible fluid flow in porous media. porous media.
Logging Services Used for Large Diameter Boreholes
Authors: Atkinson Asher , Pointer Ralph
Published: December 2007

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

Logging of large-diameter boreholes for formation evaluation and as an aid to construction has become a routine procedure at the United States Energy Research and Development Administration (ERDA) Nevada Test Site. Many of these logging services are being used in commercial applications such as mine shaft construction. Log interpretation has been altered to account for conditions of 121-cm (48 in.) to 304-cm (120 in.) diameter boreholes, generally above the water table, and penetrating volcanic rocks. The methods are described and log examples and photographs of the borehole instruments are shown. Application of the data is discussed.

Introduction

The logging of large-diameter boreholes began in 1962, in the early stages of the Unite States AEC 's Underground Nuclear Testing Program, but was limited to modified caliper and temperature instruments. Other than that, logging data were gathered from 32-cm (12 1/2-in.) diameter exploratory boreholes, drilled at the location of, but prior to the large emplacement borehole. Standard logging instruments requiring large correction factors and the costs associated with the drilling of 32-cm (12 1/2 in.) exploratory boreholes gave impetus to the development of logging equipment especially designed for the large borehole environment.

This equipment is now being used to insure the integrity of commercial mine shafts being constructed for haulage, access, and ventilation purposes. Boreholes as large as 304 cm (120 in. purposes. Boreholes as large as 304 cm (120 in. in diameter have been logged to depths of 1,830 M (6,000 ft).

LARGE BOREHOLE LOGGING SERVICES

The data acquired from logging can be divided into two categories:properties of the borehole andproperties of the formation.

Borehole properties include:hole diameter and volume,borehole temperature,level and density of material in the annulus between the casing and the borehole wall during and after cementing,level and density of the material used inside the casing around the control cables for stemming to contain the nuclear event, andvarious repair operations in the borehole prior to using it for its designed purpose.
An Investigation of Wind Induced Load on Guyline Anchors
Authors: Hoyt Phillip M.
Published: December 2007

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

Most producing oil wells in the United States include guyline anchors to provide structural support for wind loaded service derricks. Recent safety regulations have focused attention on the load transferred to these anchors during high wind, but no definitive data has been available to establish precise requirements for such loading. In order to provide accurate and broadly acceptable data, a full scale field study was conducted on an actual servicing unit subject to severe wind. Load measured on the guyline anchors during the test indicate that there is less load on the guylines than standard criteria would predict. This result seems to be a singular property of oil well servicing units and is probably associated with both the flowfield around the derrick and the vertical velocity profile of the wind.

INTRODUCTION:

Standards for the strength of guyline anchors used in conjunction with oil well servicing operations have been a matter of considerable discussion and frequent controversy. In 1970, the adoption of regulations by the Wyoming Occupational Health and Safety Commission affecting Wyoming oilfields sparked considerable interest. In 1974, proposed expanded rules (later adopted in 1975) increased this interest to new proportions as the required capacity logically was made a function of anchor location. Various calculations produced diverse results, and the Wyoming standard was ultimately adopted to incorporate the highest of these values. A safe standard was thus assured, but the result was deemed to be overly conservative by oil producers who supply the anchors. With other states apparently ready to adopt similar standards, the time seemed appropriate for a definitive field study to establish the true value of anchor load through field testing. A cooperative effort by the Wyoming Occupational Health and Safety Commission and the Rocky Mountain Oil and Gas Association, under financial sponsorship of the latter organization, produced such a test. Many interesting factors associated with well servicing were quantified during the test, but by far the most interesting were the anchor loads themselves. These loads are the focus of the study.

TEST SITE:

The site chosen was the top of a low knoll on a relatively flat plain at Cooper Cove, approximately 35 miles northwest of Laramie, Wyoming.
Comparative Assessment of Natural Gas Hydrate Production Models
Authors: Sawyer W. K. , Boyer II C. M. , Frantz J. H. , Yost II A. B.
Published: December 2007

Methane hydrates represent a potentially enormous supply of natural gas, assuming the technology can be developed for commercial gas production from this reservoir type. An important part of this required technology is the development of mathematical models for predicting methane production rates for various field operational strategies. This paper presents a review and analysis of ten types of predictive models for gas hydrates. These models vary from simple energy balance models, to single-phase analytical porous-flow models, to robust three dimensional, three-phase numerical simulators. The models can be broadly classified into depressurization models, and thermal injection models. Each of the ten models focused on specific characteristics of the dissociation, migration, and production of methane from gas hydrates. The models are compared based on what we believe are necessary features for a full-featured hydrate simulator.
Relevant Time Update of an Earth Model with Logging While Drilling Data
Authors: Marshall G. , Holt J. , Winters W. , Evans S.
Published: December 2007

The drive for greater efficiency combined with the ever-increasing complexity of today's wells requires operators to search for improved methods of working. This has led to the introduction of better tools to facilitate data integration. The high costs of drilling in deep-water operations require that communications between disciplines be optimized. One way of ensuring that the latest information is being used across disciplines is to combine down-hole data with seismic interpretations on a "relevant time" basis. A flexible system has been developed which integrates real-time data capture and management tools with geoscience interpretation and well design software.

This paper illustrates gains that are possible in the well construction process through improved utilization of the available data from the wellbore and the rigsite. Two recent case studies are presented from the Deepwater Gulf of Mexico and West of Shetland, UKCS. Logging While Drilling (LWD) data were transmitted from down-hole to onshore, then into a shared earth seismic model on a "relevant time" basis. This data integration allowed the well operations team to make a significant correction to the planned casing point during the drilling of the Gulf of Mexico well by having a detailed correlation of the logging data to the seismic model used to plan the well. It is believed that this technique and related ones will yield further examples of operational efficiency through "relevant time" data integration. This project also illustrates the benefits of close collaboration between an E&P operating company and its vendors.
California Division of Oil, Gas, and Geothermal Resources: Idle Well Management Program
Authors: Hesson Bruce H. , Glinzak Mike
Published: December 2007

To address the increasing number of long-term idle wells in California, the Department of Conservation's Division of Oil, Gas, and Geothermal Resources (Division) worked with the U.S. Bureau of Land Management (BLM) and oil industry representatives to develop strategies to reduce the idle well inventory and lower the State's potential well plugging liability. This process resulted in the development of new statutes in the Public Resources Code (PRC) that require additional financial assurances through increased well bonding, higher idle well fees, and increased orphan-well plugging and abandonment funds for the Division. Operators with long-term idle wells are also required to develop idle well management and elimination plans that focus on wells that have been shut-in for ten years, or more. In addition, idle well testing is required to protect freshwater and hydrocarbon resources, and to help determine a well's future resource potential. This paper will discuss the historic idle well trends that led to this proactive program, the specific statutes and program requirements and the program goals.
On By-Extraction of the Gold From Petroleum
Authors: Sotnikov A. V. , Sterlina N. B
Published: December 2007

The naphthides are considred as promising sources of extraction of various metals: V, Mo, U, etc. The idea emphasized in this paper is completing this list with the gold. The authors had a chance to study this problem when making a geological map and searching for the gold ores and placers for the Yagodnoye Geological Survey Department, in the Magadan region, North-Eeast Siberia. Here, high absorption abilities of petroleum with respect to gold was used in laboratory analyses. Later on, the research was continued at a natural object: the Talin Oil Field in the Middle Ob area, West Siberia. Here, the rocks of the oil collector are represented by the alluvial quartz sands and the gravelites of the Sherkalin horizon (J1) of the Tyumen set (J1+2). Accumulation material of the horizon oil deposits is the upper paleosoic rocks of the Ural-Siberian folded region. In the other similar deposits, significant industrial ore bodies and placers of gold are known. Hence, it was natural to assume a gold presence in the ancient alluvium of the Sherkalin horizon due to a buried gold placer. The testing verified these assumptions. In all three samples taken from this oil field, the atomic-absorptional method showed concentrations of gold much higher than 1 g/t. This is quite comparable to the average industrial gold concentrations, which are 4 to 10 g/t for ore mines, and 0.2 to 1 g/t for placers.
Fresh Water Injection Stimulation in a Deep Tight Oil Reservoir
Authors: Wong S. W. , O'Dell P. M. , de Pater C. J. , Shaoul J.
Published: December 2007

The Athel exploration play in the South of Oman contains a huge oil reserve, but in rather unusual reservoirs with very low permeability. Two discovered fields, Al Noor and Al Shomou carry a total oil in-place in excess of 2 billion barrels. These reservoirs contain thick silicilyte slabs that are encased in salt and shale. Due to low permeability, effective well stimulation plays a crucial role in economic field development.

There was evidence that silicilyte cores contained salt and it was believed that removing the salt with a simple fresh water soak could increase the permeability. Subsequently, a series of fresh water injection experiments was conducted in an Athel well, in 1995-97. In total, more than 16000 m3 (100,000 bbl) were injected. The aim was to wash the salt from the matrix, increasing the near wellbore permeability and hence, improving productivity. The well was indeed stimulated by these treatments, but the improved productivity did not last for very long.

Later, we suspected that the fresh water injection could have resulted in fracture propagation, or other production improvement mechanisms. A fresh look at the injection and production test data was conducted in 1998, with the objective of assessing the applicability of water-frac treatments. This could potentially eliminate or significantly reduce the need for proppant in fracture treatments.

The study showed that the production improvement was not due to matrix salt washing. In fact, hydraulic fractures were propagated. But the production response after the final and largest volume fresh water injection was complex and difficult to model. Apparently, in addition to fracture propagation, a large cavity was also dissolved in the overlying salt layer. The back production of salt saturated water, and increasing storage coefficient as derived from successive well test analysis could be related to the creation of such a cavity. In addition, the rock might have dilated, contributing to the short lived, but significant production increase. The study concluded that so-called "water-frac" treatments would need proppant to maintain fracture conductivity in the Athel.

This paper presents a field case of a novel stimulation method in tight reservoir rock. The methodology of integrating well tests analyses, production logs and fracture geometry simulations to obtain a comprehensive reservoir stimulation model is outlined. The production mechanisms induced by the fresh water injection and the cause of the rapid productivity decline is described.
New Float Collar Design to Eliminate Wet Shoe Tracks
Authors: Hibbeler Jeff , Graham Tim , Ehlinger Jeff
Published: December 2007

Wet shoe tracks are a common problem in oilwell cementing. The problem can range from a simple nuisance to many hours of lost rig time costing thousands of dollars. In most cases over retardation or bad cement plugs are blamed for this problem, but a new mechanism has been identified, which may be far more prevalent.

A "Wet" shoe track is defined as the occurrence of unset, contaminated or no cement in the casing section between float collar and shoe after a primary cement job. Wet shoe tracks are a common occurrence in oilwell cementing and many hours of lost rig time can be attributed to the problem. The most common explanation is; over retardation of cement slurry due to over estimation of BHCT. However, the authors have found another mechanism, which, to date, has not been addressed.

In JVPC Rang Dong oil field located offshore of Vietnam, horizontal wells are used to fully access the Miocene sand and Basement granite reservoirs. Productive zones are drilled with a thixotropic mud designed to enhance drilling. Ten-minute Gel Strengths of over 140 cp have been reported for these muds. While running production casing to depth, mud in the shoe track remains static for periods of many hours. Due to thixotropy, static mud gel strengths get very high and mobility is greatly reduced. Then, when the cement job is performed, cement slurry channels a small path through the viscous mud for some distance. The mechanism for this is two fold; 1) viscosity differential and 2) inside diameter (ID) change at the collar. Diameter change refers to the valve assembly O.D. versus the casing I.D. This profile forces fluid directly ahead. The analogy is – pinching a garden hose to make water travel further. These mechanisms can leave the shoe track with large amounts of mud and/or contaminated, unset cement. Further, thixotropic mud combined with solids settling in a horizontal wells makes the problem even more severe. "Low-side" mud/solids removal then becomes nearly impossible with conventional float equipment.

To address this issue, the authors made a simple design change to the standard float collar, which affects the velocity profile at the fluid exit point. A fluid diversion plate is inserted just below the collar check valve to create a 360-degree, turbulent, spray of fluid similar to the common showerhead (hereafter referred to as the Showerhead Float Collar or SFC). Using a taper profile on the holes in the diversion plate enhances turbulence. The result is complete mud removal within the shoe track even with highly viscous muds. This paper describes the new design and also reviews successful case studies from Vietnam.
The Drilling and Completion of the First Monobore Well in Peninsular Malaysia
Authors: Mohammad Aminuddin , Maung U Mya
Published: December 2007

During a recent revisit (October 1999) to Duyong Field, Offshore Peninsular Malaysia, the operator Petronas Carigali Sdn Bhd (PCSB) was able to drill through the troublesome Terengganu Shale and successfully completed a well in the productive Tapis Gas Sands. The well, Duyong A-4 STR4D (DYA-4STR4D) was drilled and completed under approved budget with minimal lost time. DYA-4STR4D was the first 3-1/2" monobore completion by PCSB in Peninsular Malaysia, paving the way for future application of the technology especially for the development of marginal oil and gas fields. This paper will summarize the design, planning and execution of this milestone achievement for PCSB.
Specialized PDC Bit Improves Efficiency of Rotary Steering Drilling Tools in Demanding Directional Drilling Programs
Authors: Mensa-Wilmot Graham , Krepp Tony , Hill Richard
Published: December 2007

Directional drilling technology, in addition to several other benefits, has aided the development of petroleum reserves in environmentally sensitive areas, and locations with limited surface access. Since their introduction almost four decades ago, improvements in positive displacement motors1(PDM) technology have contributed immensely to this drilling process.

Steerable PDMs are normally run in alternating "sliding" and "rotating" modes, in accordance with well profile requirements. As operational objectives became more challenging, it became evident that the industry had reached a plateau, with regard to PDM effectiveness2. Most wells now have 3-D profiles, extended reaches (ERD) and much deeper targets. Directional wells have comparatively higher operational costs, which grows exponentially with increases in well profile complexities.

To help drill such intricate wells effectively, at manageable operational costs, industry research efforts have focused on the development of expert technologies3,4,5 and products, one of which is the rotary steerable tool 6,7 (RST). These tools achieve needed changes to wellbore trajectory (inclination and azimuth) while the drill string is in full rotation – rotary mode drilling. This advantage improves hole cleaning and wellbore quality. Complete rotary mode drilling, made possible with RST tools reduces wellbore tortuosity, torque and drag.

It enhances weight on bit (WOB) transfer and drastically improves rate of penetration (ROP).

RST tools are extremely complicated and have high maintenance costs, because of their architecture, component life and the harsh environments in which they are used. However, when the benefits listed above for RST drilling are achieved, substantial savings in operational costs are realized. In RST drilling programs, it is critical to use the appropriate drill bit technology, since the drill bit plays a huge part in the possible achievement of the identified RST benefits.

This paper will discuss the functional medium of RST tools. It will describe the development of a new PDC bit technology, which has been specifically engineered to establish operational compatibility with RST tools and enables achievement of their operational benefits. Performance improvements achieved with the specialized PDC bit/RST tool combination will also be discussed.
Skip One String - A New Casing & Completion Philosophy for Super Slanted and Horizontal Wells
Authors: Sackmaier W. E.
Published: December 2007

In mature areas well construction costs are the primary obstacle in the development of marginal fields. Implementing more targets into one well path can reduce the exploratory risk. Horizontal wells can help to reduce development costs. However, these wells represent a major cost factor. To reduce horizontal well costs a new casing and completion philosophy, saving the intermediate casing string across the build up section was worked out. Substantial savings result from reduced logging and casing program. Moreover, the concept provides utmost flexibility to actual production requirements. Applying the new concept well costs can be reduced by approximately 30%.

An example of a recently drilled super slanted appraisal well is given. To improve project economics several secondary targets were included in the well path. To even more reduce well costs, starting from the kick off point the well was drilled in one run, with one bit and one bottom hole assembly. Unfortunately the primary target did not come in. But especially under these conditions the concept proved to be most economical.
An Experimental and Theoretical Study of Two-Phase Flow in Horizontal or Slightly Deviated Fully Eccentric Annuli
Authors: Lage A. C. V. M. , Rommetveit R. , Time R. W.
Published: December 2007

A mechanistic model is formulated to predict the flow behavior of two-phase mixtures in horizontal or slightly inclined fully eccentric annuli. The model is composed of a procedure for flow pattern prediction and a set of independent models for calculating gas fraction and pressure drop in stratified, intermittent, dispersed bubble, and annular flow.

Small-scale experimental data performed in a 50 m long straight 4" (101.6 mm) ID pipe containing a 2" (50.8 mm) OD tube lying at the bottom validate the predictions of the model. Test matrix covered not only the horizontal inclination, but also –4° and +4° relative to the horizontal. A total number of 115 tests were carried out with the following mixtures: (1) air and water were used in 61, and (2) diesel oil and N2 in 54 tests.

The mechanistic model presents also better performance when compared to the results of some empirical models, as the Beggs and Brill1 correlation and a modified version of the Aziz, Govier, and Fogarasi2 method.
Drilling Practices and Sweep Selection for Efficient Hole Cleaning in Deviated Wellbores
Authors: Power D. J. , Hight C. , Weisinger D. , Rimer C.
Published: December 2007

Cuttings transport in highly deviated wellbores is more challenging and critical than in vertical wells. By optimizing drilling practices and sweep programs, on bottom drilling time can be increased and the need for wiper trips minimized. Data from two geological side tracks drilled from the same vertical wellbore are used to demonstrate the improved efficiencies possible when using weighted sweeps rather than high viscosity sweeps for hole cleaning in deviated wellbores. In the examples discussed in this paper, over $500,000 in savings were realized by the operator through using optimized drilling practices and engineered sweeps. Optimizing the use of rotation and circulation versus continuous sliding also can contribute to improved drilling efficiency. In addition, computer simulation data are presented to support the field observations. The use of sweep reports is an integral component of tracking sweep performance.
Wellbore Stability and Formation Damage Considerations for Bekok Field K Formation
Authors: Saidin S. , Smith S. P. T.
Published: December 2007

Previous production drilling in the Bekok field has demonstrated two major challenges to a successful campaign. Firstly, substantial borehole instability can be encountered when drilling deviated wells through the Terengganu shale (K shale). The K shale was previously thought to be a reactive shale and that the problem originated from fluid-shale interactions. Secondly, invert emulsion oil based mud had previously been utilised on earlier production drilling but substantial productivity impairment was experienced against the K sands.

A study of three synthetic based mud systems was carried out in return permeability tests on K sand cores. One emulsifier system was identified as demonstrating significantly less impairment. This system when applied, allowed for good productivity in the K reservoir.

Exploration wells drilled with potassium chloride polymer muds showed low potassium depletion levels, suggesting that the shales were not reactive. XRD/XRF analysis of side wall cores from offset fields indicated that the shales consisted dominantly of small surface area clays, Table 1. This mineralogy and the low salinities of the shales suggested that the shales might be relatively weak. Table 1.SELIGI SHALE MINERALOGY ANALYSIS (Courtesy of Esso Production Malaysia Inc.)WellDepth (ft)FormationSurface Area m2/gIllite %Kaolinite %Chlorite %Montmorrilonite %Seligi 33820 – 3840J17243.217.911.91.4"4440 – 4470K199"4650 – 4680K17921.834.321.10.8"5790 – 5810L111"5830 – 5850L17839.0"5870 – 5890L16840.423.213.9not detectedSeligi 43670 – 3700J14539.012.212.20.6"4510 – 4540K20751.217.1140.7"4960 – 4990K217"5780 – 5800L168"6060 – 6075L17835.314.49.85.9"6620 – 6640L176Seligi 93937 – 3970J13445.614.211.4not detected"4692 – 4725K195"5020 – 5053K17842.122.242.1not detected"5151 – 5184L195"6168 – 6201L17148.416.714.3not detected"6267 – 6300L129

A study of the Malay Basin shales using extended leak off tests, electric log data and tests on shale core provided a geomechanics model that gave minimal wellbore instability. Field experience further defined the model. The application of required mud weight support to balance induced stress resulted in greatly enhanced wellbore stability.

Bekok B-12 well was the first well in the Bekok field revisit to pass through the K shale to penetrate the K reservoir and as such is a test well for the studies made prior to drilling operations.
Abstract Of A Proposed Paper Entitled Koh Determinations Used To Control Field Development
Authors: Jordan W.V. , Smith B.K.
Published: December 2007

Introduction

This paper deals with the use of Koh* determinations from pressure build-up curves as a controlling factor in primary field development. This method was recently utilized in the Ackerly (Dean Sand) Field, Dawson County, Texas. In this field conventional engineering calculations used to determine ultimate recovery, and thus profitable drilling locations, were not reliable.

The Dean Sand reservoir in the Ackerly Field occurs at an approximate depth of 8530 feet, has a gross thickness of 250 feet and lithologically is an extremely dirty silt stone. Core data indicate an average porosity of 10 percent and a matrix permeability of 0.1 millidarcy. Core inspections indicate a minute vertical fracture system. The formation must be artificially stimulated to obtain commercial production.
New Safe Mud Weight Window Representations to Prevent Wellbore Instability
Authors: Liz-Losada Ramiro J. , Alejano Leandro R.
Published: December 2007

Wellbore stability-related problems are one of the main sources of time and money losses in any drilling operation. This is the reason why, in the last years, many improvements have been made in this specific field of research. The improvements are based on a better knowledge of the mechanisms that originate rock failure. One of the key parameters to be controlled and monitored while drilling is that of the mud weight. In order to avoid well instability, a new graphical representation of the safe mud weight window is presented. This new graphical solution is intended to ease the estimation of the values that guarantee well stability, either in tension or compression, at any depth, based on the geomechanical properties of the formations crossed while drilling.
Oil and Gas in the Energy Mix of the 21st Century
Authors: Fanchi John R.
Published: December 2007

Energy demand is expected to grow over the next century as more countries seek a better quality of life for their citizens. The energy demand will be met by a global energy mix that is undergoing a transition from an energy portfolio dominated by fossil fuels to an energy portfolio that includes a range of fuel types. This paper presents an overview of energy sources available for use in the 21st century and a prediction of the contribution of hydrocarbon oil and gas to the 21st century energy mix. It then includes a discussion of the implications for petroleum engineering education and the emergence of a new type of energy industry.
Cross-Discipline Integration in Reservoir Modeling: The Impact on Fluid Flow Simulation and Reservoir Management
Authors: Al Qassab Hisham M. , Fitzmaurice John , Al-Ali Zaki A. , Al-Khalifa Mohammed A. , Aktas G. A. , Glover Paul W.
Published: December 2007

A new technique is developed for modeling 3D permeability distributions. The technique integrates all available data into a fluid flow simulation model. The integrated modeling process honors the essential aspects of the established reservoir descriptions as well as the geological facies model and engineering data. The added value of data integration of the fluid flow simulation is illustrated by the improved accuracy of the resulting well performance predictions and the decrease in time requirements for reservoir modeling history matching.

The technique utilizes diverse data at different scales to condition reservoir models of facies, porosity, and permeability. Such data includes 3D seismic, well logs, core measurements, geologic facies distribution, flow meter logs, and pressure buildup tests. The model building process explicitly accounts for the difference in scale of the various measurements. The model calculates the porosity, facies, and permeability in the inter well volume using geostatistical techniques that are constrained by seismic impedance derived from the 3D seismic data. The use of engineering data in the permeability modeling constrains the results and decreases the history matching time requirements.

A case study demonstrates the modeling technique. A reservoir model is developed for the Unayzah Formation in the Hawtah Field of Saudi Arabia. The Unayzah is a highly stratified clastic reservoir in a mixed fluvial and eolian depositional environment. Data integration provided more realistic reservoir model for this complex geologic setting than the conventional approach. Specifically, the integrated approach provide a reservoir model that captured the complex and highly stratified nature of the lithological units. Fluid flow simulation was carried out for both the new integrated reservoir model and the conventional reservoir model. Results show tremendous savings in history matching time and more accurate results for use in reservoir management production strategies when applying the new technique.
Application of Genetic Algorithms in Portfolio Optimization for the Oil and Gas Industry
Authors: Fichter Daniel P.
Published: December 2007

Portfolio management and optimization techniques are becoming increasingly important in the oil and gas industry. As the number of project opportunities grows the corporate or financial planner is faced with an increasingly difficult task. Mathematical search and optimization algorithms can greatly simplify the planning process. A particularly well suited class of algorithms for oil and gas optimizations are Genetic Algorithms. This paper will discuss the application of Genetic Algorithms in oil and gas portfolio optimization.

We will show that Genetic Algorithm’s are excellent at handling accurate and complex, non-linear business models. This class of algorithms is capable of scaling upwards of a thousand projects, well beyond the reach of traditional methods. Genetic Algorithm’s are capable of generating multiple ‘good’ solutions, providing an opportunity to explore alternative characteristics of the portfolios, including value and risk measures. A portfolio analyst can request to keep non-viable solutions that best satisfy the business constraints. This will be shown with a hypothetical, yet realistic set of oil and gas projects, which will be modeled and analyzed on a personal computer.
Determining Consistently the A Priori Information Weight in a Stratigraphie Inversion
Authors: Fournier F. , Perdrizet T. , Royer J. J.
Published: December 2007

Stratigraphie inversion of seismic amplitudes is a widely-used technique for estimating acoustic or elastic impedances, these impedances being related to reservoir properties in a second step. For inversion processes incorporating a priori information, it is very important to weight the a priori in the cost function, consistently with the a priori uncertainties. The a priori model is built from kriging impedance values at wells along stratigraphic correlation surfaces. The covariance of the kriging error is derived from a theoretical analysis. This covariance is approximated either by a stationary or by a locally-stationary exponential covariance. In both cases, the parameters (range and standard deviation) of the approximated covariance are a priori weights consistent with the true spatial structure of the a priori uncertainties. This methodology significantly changes the a priori weights, that were before simply user-defined, leading therefore to a different estimated impedance field, more coherent with all integrated data.