bluuebunny/crossref_metadata_2025 huggingface dataset:
Results of a 1995 Hydraulic Fracturing Survey and a Comparison of 1995 and 1990 Industry Practices
Authors: Carter Ronald H. , Holditch Stephen A. , Wolhart Stephen L.
Published: December 2007

This paper presents the results of a hydraulic fracturing survey conducted in 1995 on behalf of the Gas Research Institute (GRI). The purpose of the survey was to determine the types of formations that are normally fracture treated; gather data on the fracture treatments that are normally pumped; determine the level of data collection being conducted in the field; determine the level of data analysis being conducted in the office and the field; solicit opinions on the level of technology required to obtain an accurate analysis for fracture treatments; solicit opinions of the limitations of current technology; determine what costs operators could justify to analyze fracture treatment data and obtain ideas on new areas of research. Data gathered in the survey included respondents’ company size (major, large/small independent, service company or consultant), geographical area of operation, well depths and permeabilities, fracture treatment size, proppant type and volume, level of detail in data gathering, fracture treatment design and real-time analysis. The 1995 data were compared to a similar survey conducted in 1990 by GRI to determine technology trends.
Supercharge Pressure Compensation Using a New Wireline Testing Method and Newly Developed Early Time Spherical Flow Model
Authors: Proett Mark A. , Chin Wilson C.
Published: December 2007

Wireline formation testers are increasingly being used to obtain formation pressure and permeability measurements, which in turn are used in geological evaluations and in designing well completions. It is generally assumed that the pressure measured by the tester probe is near formation pressure. Unfortunately, in many instances, such as in low permeability formations, the mudcake does not adequately isolate the hydrostatic pressure in the wellbore from the formation. As a result, the sandface pressure measured with the formation tester is "supercharged" and not the formation pressure after all. This sandface pressure may be as much as 1,000 psi over the actual formation pressure of interest. This paper demonstrates that a new analytical model can be used along with a new testing technique to correct the measured pressure to actual formation pressure. A high accuracy finite element near-wellbore simulator (NEWS†) is used to test the sensitivity of the analytical model. Log examples are presented to demonstrate the success of the new testing technique.
The Determination and Considerations of Induced Fracture Strike
Authors: Blomberg John R.
Published: December 2007

The determination of induced fracture strike is an important factor in both the primary and secondary development of oil and primary and secondary development of oil and gas reservoirs. If a common strike can be substantiated for a field or area, ultimate recoveries can be increased through exploiting the reservoir on a development pattern that conforms to the induced fracture strike.

This paper is a practical discussion of the use of the Borehole Televiewer log in wells in the Appalachian basin to determine induced fracture strike. Log sections are presented and various applications of results are discussed. Two anomalous cases are also presented and discussed.

Introduction

The importance of determining the strike of induced or natural fractures has been recognized for some time. Early work with the Lynes packer and more recent work with softer rubber packer and more recent work with softer rubber impression packers have provided information about the strike and configuration of both natural and induced fractures. However, the impression packer procedure is sometimes costly, time-consuming and the orientation procedure at times questionable. In 1968, an open-hole logging tool patented by Mobil was introduced to the industry to define fractures and give an accurate orientation in a simple logging operation. This tool has generally given good results in wells logged in the Appalachian basin, and the results have easily been interpreted.

More emphasis has been placed on the application of fracture orientation data to planning secondary recovery. However, if planning secondary recovery. However, if primary development wells are completed with a primary development wells are completed with a fracture treatment, secondary recovery potential with respect to fracture orientation must be considered from the start of initial field development.

One of the most significant field secondary recovery developments, based on indicated natural fracture strike, was the waterflood development of the Spraberry field in West Texas. Waterflood patterns were designed to conform to the natural major fracture system to maximize sweep efficiency. Several operators have installed secondary recovery project patterns to conform to the induced fracture strike, patterns to conform to the induced fracture strike, but very little is available in the literature as to how successful these efforts have been.
Application of a Transient Heat Transfer Model for Bundled, Multiphase Pipelines
Authors: Brown Trent S. , Clapham John , Danielson Thomas J. , Harris Robert G. , Erickson Dale D.
Published: December 2007

A computer model has been developed which accurately describes transient heat transfer in pipeline bundles. An arbitrary number of internal pipelines containing different fluids, flowing in either direction along with the input of heat to one or more of the fluids can be accommodated. The model is coupled to the transient, multiphase flow simulator OLGA. The lines containing the multiphase production fluids are modeled by OLGA, and the heat transfer between the internal lines, carrier pipe, and surroundings is handled by the bundle model.

The model has been applied extensively to the design of a subsea, heated bundle system for the Britannia gas condensate field in the North Sea. The 15-km bundle system contains a 14″ production line, an 8″ test line, a 3″ methanol line, and a 12″ internal heating medium line within a 37.25″ carrier. The heating medium (water) flows in the internal heating medium line and in the annulus at 82,500 BPD. The primary purpose of the bundle system is to avoid the formation of hydrates. A secondary purpose is to avoid the deposition of paraffin. The bundle model was used to 1) compare the merits of two coaxial lines vs. a single bundle; 2) optimize the insulation levels on the carrier and internal lines; 3) determine the minimum time required to heat up the bundle; 4) determine heat input requirements to avoid hydrates throughout the field life, 5) determine temperature profiles along the lines for a range of production rates; 6) study ruptures of the production line into the bundle annulus; 7) determine minimum temperatures during depressurization; and 8) determine cool-down times. The results of these studies were used to size lines, select insulation levels, assess erosion potential, design for thermal expansion-induced stresses, and to select materials of construction.
The Influence of Drilling Variables on Barite Sag
Authors: Bern P. A. , Zamora M. , Slater K. S. , Hearn P. J.
Published: December 2007

Barite sag is a significant variation in mud density caused by the settlement of barite or other weight material in high-angle wells. The wide fluctuations in mud weight can lead to severe operational problems, including well-control, induced wellbore instability, downhole mud losses, and stuck pipe.

A laboratory flow loop has been used to evaluate the influence of key drilling parameters on barite sag. Results show that the highest sag occurs at angles in the region 60-75°, particularly at low annular velocities. Drillpipe rotation is shown to be particularly beneficial in minimising barite settlement. Rotation also assists in re-distributing barite deposits formed on the low side of the hole. Data from the tests clearly demonstrate the interdependence of drillpipe eccentricity, rotation, and mud flow rate.

Results from the study have been combined with field observations to develop guidelines to minimise barite sag and manage the associated risks. The conclusions of the study are that barite sag can be minimised by attention to detail at the planning and execution stages of drilling a well. In particular, recommendations in four key areas are addressed: well planning, mud properties and testing, operational practices, and wellsite monitoring procedures.
Thermal Stimulation and Mechanical Techniques Permit Increased Recovery from Unconsolidated Viscous Oil Reservoir
Authors: Holke David C. , Huebner William B.
Published: December 2007

Introduction

The Northeast Butterly Oil Creek unit is located in Garvin County, Okla., along the northern flank of the Arbuckle Mountains. Production from this field is from the Basal Oil Production from this field is from the Basal Oil Creek sand of the Simpson group, Ordovician age, at an average depth of 4,200 ft. The formation is characterized by a relatively homogeneous sand section, which is mostly unconsolidated with limey streaks through the section. The porosity is 24.3 percent with the median porosity is 24.3 percent with the median horizontal and vertical permeabilities to air 850 and 700 md, respectively. Total pay thickness is 143 ft. The natural producing mechanism is an active water drive.

The field is considered an anticlinal high, buttressing a major fault with many cross faults dividing the pool as shown in Fig. 1. Dips as high as 40 degrees exist in many parts of the field.

Encompassing only 165 acres, this field has produced 3,575,000 bbl of oil; total original produced 3,575,000 bbl of oil; total original oil in place is estimated to be 27 million bbl. It is the purpose of this paper to share some of the technology that is being used to produce this 13 degrees API gravity crude. Through the use of thermal stimulation and mechanical techniques, the recovery of this viscous, highly emulsified, sand-laden fluid has been accomplished. Reservoir and fluid characteristics are shown in Table 1.

PRIMARY PRODUCTION Because of its reserves and potential production, the Northeast Butterly Oil Creek production, the Northeast Butterly Oil Creek reservoir has attracted considerable engineering attention since its discovery. Peak production was in Aug., 1948, at a rate of 1,650 B/D. Most wells were completed for greater than 200 B/D.

A total of 13 wells were drilled from 1946 to 1948, of which one was a dry hole and one was plugged because of mechanical difficulties. As plugged because of mechanical difficulties. As wells reached high water-oil ratios, they were shut in due to being uneconomical and for lack of disposal facilities. Production declined to 3,500 bbl/month from 1957 until 1964, when thermal activities were initiated (Fig. 2).

THERMAL STIMULATION

The viscosity of the Butterly crude is approximately 2,000 cp at reservoir conditions. As can be seen on the viscosity-vs-temperature curve (Fig. 3), by raising the reservoir temperature 100 degrees F or more, the crude viscosity can be appreciably reduced. With this fact in mind, a preliminary investigation was made in 1959, followed by a feasibility study in 1962 to determine the applicability of thermal stimulation at Northeast Butterly.
Shale Drilling with Oil Muds
Authors: Methven Norbert E. , Barthel Horst
Published: December 2007

Significant strides have recently been achieved in minimizing shale problems while drilling. A primary contribution is the use of oil base mud wherein the chemical potential of any water phase in the mud is balanced with the chemical potential of the formation to preclude a reaction between the two.

This paper presents a summary of shale and clay theory and laboratory data to aid the definition of wellbore stability problems. These data include water content versus relative vapor pressures for clays and shales which can be related to downhole conditions for establishing the optimal properties of an oil mud aqueous phase. Also included are relative vapor pressure data for aqueous phases with various salts and concentrations. phases with various salts and concentrations. These data are then used to prescribe the mud properties to preclude wellbore instability properties to preclude wellbore instability while drilling.

Compromises are necessary when trying to match the aqueous phase of a mud to the requirements of the formation. These compromises occur when information is not available in the region of interest. Also compromise occur often because the exposed shales in a well will have varying requirements, but will be exposed simultaneously to a single mud system. Another case occurs when drilling through salt sections which causes the aqueous phase of a mud to be altered. The sensitivity phase of a mud to be altered. The sensitivity of such compromises is aggravated by time of exposure and by high water content oil muds. Therefore, these compromises can be critical where invert oil emulsion muds are used because they require high water percentages in order to function.

An oil base mud does not require water to function. Therefore, the effects of these compromises can be avoided with the use of an anhydrous oil base mud or can be minimized with/the use of a low water content oil base mud. Laboratory and field data confirm these principles and are included in this paper.
Sand Exclusion by Pressure Packing Through Perforations
Authors: Shyrock S.H. , Watkins W.R.
Published: December 2007

Entry of formation fines and sand into oil and gas producing wells has been a continuing problem for many years. Methods of controlling problem for many years. Methods of controlling this entry have been developed and many fine papers presented on their merits. papers presented on their merits. In this paper, the authors suggest a method which was developed to reduce the cost of well completions and provide greater versatility in down hole control to those drilling wells for production from poorly consolidated sandstone production from poorly consolidated sandstone formations.

One major difference in the method described in this paper is that of attempting to obtain total sand exclusion. Earlier methods have been successful in obtaining sand control, but some small amount of sand or fines might still enter the well and damage the tubular goods.

Placement of a gravel media surrounding the perforated casing extending through the productive perforated casing extending through the productive zone can often be difficult, particularly in wells directionally drilled and having long or multiple producing zones. This method, which we have chosen, producing zones. This method, which we have chosen, to call "Pressure Packing Through Perforations," has proven not to be as difficult nor as expensive.

The application of this method to several wells located in the Oak Park Field, Ventura County, California, are discussed along with the description of the technique. It is believed that this method can well have application to oil and gas fields throughout the world where sand control or exclusion is desired.

Introduction

When one becomes concerned and seeks to find a method to exclude formation sand entry, it should be recognized that in order to accomplish this, one thing necessary to know is what size the pack sand must be. Formation sampling in these poorly consolidated formations is no easy task and often is thought to be impractical. The practice has been to use the smallest practical sand size in lieu of formation sampling, which if all other features of the technique are optimized, provides a reasonable degree of confidence.

Excellent papers have been published dealing with formation sampling and pack sand selection. In order to present this technique criteria adequately, we will forego quoting exerts from these publications, but suggest your referring to them.
Successful Drilling of an Underbalanced Horizontal Well in the Rigel Halfway Pool - Laboratory Screening and Field Results
Authors: Doane R. D. , Bennion D. B. , Eilers D. M. , New E. R.
Published: December 2007

The Middle Triassic Halfway formation in northeastern British Columbia is a high quality, well sorted quartzose sublitharenite. Past drilling operations using conventional overbalanced technology in the reservoir had indicated significant formation damage occurred due to a combination of mechanical and chemical formation damage effects associated with the loss of drilling fluid to the formation. A series of compatibility and special core analysis tests were conducted to refine an underbalanced drilling procedure with natural gas for a 300 m long horizontal well in the formation using a natural gas-mist hydrocarbon system at a 1400 kPa underbalance pressure level. The well was drilled successfully and flowed at peak rates of up to 1100 m3/day (almost 7000 bbl/day) of oil and 340,000 m3/day (12,000,000 scf/day) of gas during the underbalanced drilling operation. Post test pressure transient and interference tests indicated an in-situ permeability of 150 mD with zero skin factor indicating that the well had been drilled successfully in an undamaged fashion. The well has currently produced close to 13,000 m3 of oil (80,000 bbl) and over 11,000,000 m3 (400 MMscf) of gas with initial AOF potential of approximately 520 m3/day (3300 bbl/day).
State-Of-The-Art Cuttings Transport in Horizontal Wellbores
Authors: Pilehvari Ali A. , Azar J. J. , Shirazi Siamack A.
Published: December 2007

In the ever growing directional and horizontal drilling, hole cleaning is a common and costly problem. It can become particularly critical in the case of extended reach drilling, where larger and longer wellbores are drilled. During the past two decades, especially in the recent years, many laboratory studies as well as field observations have been directed to address the cuttings transport problem. This has resulted in better understanding of the subject, and some remedies to overcome the problems. Several correlations/models have also been developed which give the field engineer a tool to better specify hydraulic requirements to clean the hole. However, due to the complexity of the subject, a comprehensive and proven model, not existing at this time, requires much more laboratory research and field studies. This will be the major topic addressed in this article.
Pseudo-Horizontal Well: Alternative to Horizontal and Vertical Wells
Authors: Zakirov S. N. , Zakirov E. S.
Published: December 2007

Horizontal wells are getting more and more widely used in oil and gas fields development due to plenty of its merits. However, there are examples when horizontal well drilling did not justify hopes. It is shown in this paper, that layered and anisotropic structure of the reservoir may lead to decrease of initial oil flow rates of horizontal wells and final oil recovery factors (ORF) reduction too. It is proved that pseudohorizontal wells may incorporate advantages of vertical and horizontal wells. As a result, these wells may be more efficient in comparison with both horizontal and vertical wells.
Hydraulic Fracturing of Horizontal Wells: An Update of Design and Execution Guidelines
Authors: Lietard Olivier , Ayoub Joseph , Pearson Anthony
Published: December 2007

Thousands of horizontal wells have been drilled world-wide over the last ten years. Most of them are completed openhole and do not produce as well as expected. In their design phase, adverse reservoir and wellbore effects are often underestimated, such as permeability anisotropy, well stand-off, fonnation damage, formation face damage, and sand control screen plugging.

Recent statistical surveys of the production of openhole horizontal wells have confirmed that actual performances are disappointing. They are leading to major re-evaluations of drilling and completion strategies in many present reservoir developments.

In offshore environments where a limited number of slots are available, horizontal wells remain the best choice. However they are increasingly cased, cemented, perforaled and stimulated, in order to alleviate the problems affecting openhole wells.

This paper describes how this new trend is expanding in the North Sea, and gives all necessary guidelines to successfully design and execute multiple fracturing treatments in horizontal wells. Production and treatment cost estimates are provided for all cases of fracture orientation vs. the wellbore. Radial flow effects in non-collinear geometry are detailed and Tip Screen Out (TSO) designs recommended.
Olefin Sulfonates for High Temperature Steam Mobility Control: Structure - Property Correlations
Authors: Borchardt John K. , Strycker Arden R.
Published: December 2007

Understanding the effect of the components of commercial olefin sulfonates on steam foam performance would aid manufacturing more cost-effective products. Commercial alkene sulfonates are a mixture of alkene sulfonate, hydroxyalkane sulfonate, and olefin disulfonate. The effect of these components, hydrophobe linearity, the position of the carbon-carbon double bond in the substrate (alpha-olcfin compared to internal olefin), hydrophobe carbon number, and hydrophobe linearity on foaming properties and other properties of interest for enhanced oil recovery was studied. The connectivity index measure of chemical structures correlation with 121°C (250°F) foam stability provided a correlation coefficient of 0.98.
Chemical Dehydration: Correlations between Crude Oil, Associated Water and Demulsifier Characteristics, in Real Systems
Authors: Márquez-Silva R. L. , Key S. , Mariño J. , Guzmán C. , Buitriago S.
Published: December 2007

With the aim at finding a method for the selection of a suitable demulsifier for crude oil dehydration, five crude/associated water/effective demulsifier real systems were evaluated in this study. Likewise, based on the existing knowledge about the fundamentals of emulsion stabilization process, the typical characteristics of each element of the systems, which represent the variables or factors governing the process, were chosen. These variables were: in the crude oil, the acidity number, as a measure of its polarity; in the associated water, the salinity; and in the demulsifier, the relative solubility number (RSN).

A hypothesis based on the surfactant affinity difference (SAD) model is proposed. This model was adapted to the specific case of crude oil chemical demulsification. A simplified mathematical expression was obtained, which establishes a relation between the crude oil nature, the associated water salinity, and the demulsifier hydrophilicity.

The data obtained from the evaluation of the selected characteristics were introduced into the model. As a result, the following empirical relationship was obtained: lnS=-0.77A-0.28RSN+8.17

where S is the associated water salinity and A is the crude oil acidity number, variables which are easily measured.

RSN values were calculated and compared with those obtained from experiments. Except in one case, the calculated RSN value approximates very closely the experimental one. It is therefore concluded that this correlation serves to select the appropriate demulsifier to dehydrate a given crude oil, based on the simple procedure outlined above.
Testing the Corrosivity of Spent HCl/HF Acid to 22 Cr and 13 Cr Stainless Steels
Authors: Morgenthaler Lee N. , Rhodes Peter R. , Wheaton L. L.
Published: December 2007

Combinations of HCl and HF acids are commonly used in well stimulation in sandstone reservoirs containing substantial amounts of clay and feldspar. After reaction with reservoir minerals, the resulting spent acids arc produced through production tubing. The spent acids may be diluted with formation water and contain a variety of reaction products. Corrosion inhibitors may be depleted by adsorption on formation minerals. Laboratory tests were conducted to simulate the composition of "spent" HF-containing acids and inhibitor depletion in the formation. Test conditions were based on autoclave and coreflow experiments coupled with field data on acid flowback.

Acids containing HF remain corrosive even after extensive reaction with sandstone reservoirs. Inhibitor depletion and dilution are a significant factor in spent-acid corrosivity Field data indicate that about 80% of the injected acid is produced back diluted by about a factor of two. Guidelines have been developed for simulation of spent acid compositions with synthetic laboratory brines. Using these simulated brines, corrosion tests have been performed with 21 Cr duplex stainless steel and Super 13 Cr (SI3Cr) martensitic stainless steels in spent HCl/HF mixtures under conditions typically encountered in the deepwater Gulf of Mexico. Guidelines for acid formulation and inhibitor application have been developed.
An Overview of Injection Design
Authors: Dunn-Norman S. , May E.A.
Published: December 2007

Recent advances in research have significantly improved the understanding of formation damage induced from injection operations. Specific measures, such as injector half life, and models for predicting injectivity decline have been developed to assist engineers in designing optimum injection operations.

During a similar time frame, Underground Injection Control (UIC) regulations formulated under the Safe Drinking Water Act (SDWA) have been enacted and have served as a catalyst for changes in downhole injection design and operation of injection wells.

This paper provides a concise overview of the state of injection design. The paper includes a review of fundamental injection design, presents research results in formation damage due to brine injection, and discusses the downhole design(s) currently required by law under 40 CFR (US Code of Federal Regulations).

Introduction

Formation injectivity and injectivity decline due to formation damage from inject brines, are principal concerns in waterflood (Class II) injection design. From the operators standpoint, formation damage is the principal concern because increasing damage reduces injectivity, and can affect the longevity of the injection well.

Regulatory compliance aspects of the injection operation and the environmental implications of the wellbore design are also of paramount importance. These issues determine whether an injector can be permitted, the maximum injection pressure which can be sustained, and any risks which the injector may pose to overlying sources of drinking water.

Design Considerations of Waterflood (Class II) Injection Wells.

The design of a Class II injection well must considerFormation injectivity and injection well testingFormation damage, injectivity decline and filteringRegulatory considerations for injection design

Selection of tubulars, injection pumps and surface facilities such as brine filters is made on the basis of design parameters related to these issues.

Formation Injectivity and Injection Well Testing.

Formation injectivity is one of the first parameters determined in injection design. The formation's ability to accept the injected brine will govern the tubulars and surface injection requirements. Injectivity also can affect the selection of the injection pattern and the number of injection wells per producing well in pressure maintenance and waterfloodng operations. Determination of the base formation injectivity also provides a baseline observation from which predictions of the long term injectivity of the well can be made. All of these considerations are important to the economic success of injection projects.

Well tesing techniques have been employed in injection wells to determine reservoir parameters such as injectivity, in-situ permeability and skin factor, formation parting pressure and fracture extension pressure. These techniques include injectivity tests, falloff tests and step-rate tests.
Ultrasonic Instrumentation for On-Line Monitoring of Solid Deposition in Pipes
Authors: Andersen M. I. , Isaksen Ø , Urdahl O.
Published: December 2007

Studies of the fluid- and flow properties of reservoir fluids is important to ensure an effective and safe production and transport of oil and gas. Among the many areas where it is important to gain further knowledge is the formation and deposition of hydrates and wax in pipes transporting reservoir fluids or crude oil. On this background, Christian Michelsen Research A/S (CMR) has studied various measuring techniques over the past few years, and instrumentation for deposit monitoring has, and is in the process of being developed. Recently, CMR has developed ultrasonic laboratory instrumentation for on-line monitoring of solid deposition in pipes.

The system consists of two ultrasonic "clamp-on" transducers operating in pulse-echo mode, two compact electronics units and a PC "control unit" handling all data acquisition, signal processing and presentation of results. The system has been installed on a multiphase flow "loop" at Statoil's Research Centre in Trondheim, and is designed to: 1) – detect the deposition of hydrate on the pipe wall, or 2) – measure the thickness of a possible wax layer.

In this paper, the system, its detection principles, and the results from initial tests are described and presented. The critical factors influencing the operation and robustness of the system are discussed, as well as the conditions which must be satisfied and the challenges to be met for a successful industrial application.
The Evaluation of Two Different Methods of Obtaining Injection Profiles in CO2 WAG Horizontal Injection Wells
Authors: Dollens Kimberly B. , Shoumaker James C. , Wylie Burl W. , Rice Phil , Johannessen Orjan
Published: December 2007

Two different methodologies were employed in obtaining injection profile surveys in two CO2 water-altemating-gas (WAG) horizontal injection wells in the South Cowden Unit (SCU) CO2 project. Both methods were used once during an initial water injection period to establish a baseline profile. Then, the first method was utilized on both of the horizontal injection wells during a CO2 injection period. The first method utilized a coiled tubing conveyed, memory-based logging system, including a correlation gamma ray and collar locator log; injection and shut-in temperature, capacitance, flowmeter and pressure gradient; and interface tag. The second method utilized a logging and injection program wherein coiled tubing and wireline were run in the injection well with a Y-block and coiled tubing side-entry assembly attached to the coiled tubing below the spot valve. The tool consisted of a positive and negative gamma ray and temperature tool, and utilized a slug of more than one gallon of radioactive gel rather than the standard injection volume of approximately 50 cc or 1 cc per station. Actual field results are reviewed, and the two methodologies discussed for application in CO2 WAG horizontal injection systems.
A Practical Technique to Estimate the Formation Thickness in a Kicking Well
Authors: Samuel G. Robello , Engler Thomas , Miska Stefan
Published: December 2007

Characterization of formation while drilling continues to be a challenge to the engineers. This paper describes a technique contributing to this objective. When a well kicks while drilling, evaluation of pore pressure and the corresponding kill mud density is of critical importance for the safety of the drilling crew and mechanical integrity of the wellbore. Besides the estimation of these parameters, it will be beneficial to estimate the thickness of the kicking formation prior to drilling. This helps to drill safely and carefully through the potentially active kicking formation. In this paper, it is shown how to calculate the kicking formation thickness with the limited information available at the time of an oil/gas kick. A method of data analysis (obtained on a kicking well) to estimate the formation thickness of the kicking zone is presented. Illustrative examples including actual field cases are described and analyzed.
Rigsite Information Management: Are We Making Use of Modern System's Full Potential?
Authors: Spoerker H. F. , Kroell E.
Published: December 2007

Today's rigsite information acquisition systems are demanding to the operator, costly to install and maintain and hardly friendly to inter-company networking interests. Cost-efficient solutions, integrating rigsite instrumentation with drilling data acquisition through sensor telemetry, daily drilling reporting and all additional related information services /e.g. cement job records, well logs, well tests etc.) are clearly wanted by the drilling community to enhance quality control. The paper lists experiences gained with extensive drilling rig instrumentation and drilling process information gathering systems over a period of 12 months, critically evaluating the quality and usefulness of commonly acquired drilling data as well as the actual application of such information volumes in accelerating the drilling learning curve and enhancing process and quality control. A detailed description of storing "streamed" drilling data into a large-scale multi-user relational database and the additional value of such information volumes available to the user "at his fingertips" is presented. The realization potential of such systems on low-to medium-cost on-shore drilling operations as well as the possible integration of multi-well and multi-rig systems and the buildup of field- and area-databases are presented from a service-company as well as operator standpoint. A definition of the current state-of-the-art in rigsite information management is attempted and the future potential for such systems is assessed.

Illustrations and references at end of paper
Design and Testing of a High-Performance Inflatable Packer
Authors: Eslinger D. M. , Kohli H. S.
Published: December 2007

The marginal performance and reliability of inflatable elements often restrict their use in demanding through-tubing workovers. The development and qualification of a robust, 2.12-in. OD inflatable element are reviewed. The new element has a differential pressure rating of approximately 5000 psi at 2:1 expansion and 2000 psi at 3:1 expansion at temperatures in excess of 300°F. This allows operation in wells that are more hostile than previously possible while increasing job reliability for less demanding applications.
Contribution to reservoir behaviour appraisal by television
Authors: Gay L. , Groult J.
Published: December 2007

Conventional investigation methods, such as logs, core analysis and production tests have been unable to provide data accurate enough for evaluating the Emeraude pool. In order to gather the informations, pool. In order to gather the informations, which in our opinion are essential, we have been led to use a closed circuit television system.

In order to be safely operated in a bore hole, the available television camera had to be adapted to oilfield equipment. A number of preliminary tests was necessary to achieve this goal.

This rather peculiar method provided means to assemble essential and sometimes spectacular data, which successfully completed the partial results available thus far.

Introduction

The Emeraude structure was discovered in 1969 by Elf Congo in the offshore waters of Congo-Brazzaville.

The hydrocarbon in the reservoir is an undersaturated, highly viscous oil. Pay zones are located from 200 to 650 meters (650 to 2.130 feet) and consist mostly of more or less carbonated silts, slightly consolidated or unconsolidated, with indurated limestone breaks. The latter have an average thickness of about a decimeter.

From the first wells on, the conventional formation evaluation methods proved to be insufficient, a striking example being the discrepancy between the permeability values determined from core analysis and the much higher permeability values deducted from the pressure build-up curves recorded on production tests.
Impairment of Producibility Due to Fracturing Fluid Leak-off in Oil Reservoirs?
Authors: Gadiyar B. R. , Gupta A. , Shah S. N.
Published: December 2007

This paper presents the results and interpretation for return permeability testing following the leak-off of fracturing fluid in reservoir rock samples containing movable oil saturation. The dynamic fluid loss tests were conducted with 2 inch diameter and 10 inch long core samples. The fluids used were linear guar and hydroxypropyl guar (HPG), and borate crosslinked guar and HPG, respectively. Tests were conducted with and without fluid loss additive (FLA) in order to study its effect on return permeability impairment. All tests were conducted at room temperature. The drive pressure during leak-off was 500 psi.

Following the leak-off, the cell was shut-in for a duration of at least 3 hours. In order to obtain the variation of return permeability with time and distance from the fracture face, the return permeability was determined for each 2 inch long section of the core sample. Variation of return permeability for the specified range of fracturing fluids is presented and discussed.
Screening and Design Criteria for Tangleflags Type Reservoirs
Authors: Kasraie M. , Singhal A. K. , Ito Y.
Published: December 2007

Tangleflags project is a highly successful example of a Steam Assisted Gravity Drainage (SAGD) process operated by Canadian Natural Resources Limited. The original reservoir conditions were unfavourable for steam injection : the reservoir has a small gas cap and an active bottom water, which made the primary production very unattractive. However, a judicious application of steam injection with horizontal producers made it a show case project.

This study examines the Tangleflags type of projects from the point of view of future applications (screening and design) of the SAGD process. A thermal simulator (STARS) was used, to achieve a history match of six-years' performance. Predictions for 15 years showed continued encouraging operations.

The second phase of the study involved examination of reservoir parameters and operating conditions that would lead to a successful project. For example, it was found that without using conditions of a steam trap, the steam-oil ratios would be high. Pools with oil viscosities higher than 35,000 mPa.s, and oil zone thicknesses less than 15 m were found to be unattractive. Vertical injectors (rather than horizontal), appeared to be more desirable, with an improvement in performance as the injectors are placed farther from the horizontal producer. Optimal well spacing in such a scheme, seemed to be dependent on the mobility of oil in the reservoir. Presence of an active aquifer below the formation results in severe water coning after a few years from the start of steam injection.

The results of this study are expected to be helpful in planning a Tangleflags type operation in heavy oil pools containing mobile oil, where vertical steam injectors are used around horizontal producers.
A Practical Method for Modeling Bit Performance Using Mud Logging Data
Authors: Xu Hong , Tochikawa Tetsuro , Hatakeyama Takashi
Published: December 2007

Using mud logging data, this paper presents a practical method for modeling ROP and bit life, and therefore modifying the value of Cost-Per-Unit-Depth (CPUD) calculated by using the conventional formula. For illustration, this paper shows how to identify the best bit type, the best IADC code and the best bit name/model number for a particular formation. The results appeared to be practically interprétable and physically valid. This method can be used to assist with bit selection, optimizing drilling parameters and diagnosing drilling problems.
Strength calculation on a semi-submersible drilling platform
Authors: van Holst M.
Published: December 2007

1. Abstract

The paper describes the motions and overall strength analysis as used for the design of the semi-submersibie drilling platform Norrig, fig. 1, with an emphasis on the calculation of the loads on the structure in floating condition.

The motions are treated as a linear problem according to a method described by Hooft. Experiments and full scale measurements have shown that this method gives acceptable results. For the determination of the waveloads on the floating structure no attempt at linearization has been made. The most important non-linear feature is that the waveloads run the length of the actually submerged part of the construction.

The loads and internal forces are determined at certain points of time and cannot be expressed as amplitudes and phase angles. Consequently the step to a probabilistic approach of the strength problem cannot be made and the strength analysis has been performed using a design wave.

The construction of a system of forces in dynamic equilibrium at the points of time under consideration is a notable feature of the described method.

When the loads have been determined the strength analysis is performed using the frame analysis program STRESS.

The internal forces are transformed to stresses and checked using the AISC rules.
Taking Advantage of 3-Dimensional Visualization in Drilling Operations
Authors: Guerrero J. Victor
Published: December 2007

This paper illustrates the benefits of utilizing 3-dimensional visualization as a tool to integrate engineering analysis in drilling operations. Studies reveal that integrating new and existing technologies in advanced graphics with engineering analysis results in improved drilling operations which:–Increase well planning effectiveness and accuracy–Maximize reservoir exploitation and drainage–Significantly lower the risk of collisions, thereby reducing the overall exposure to economic and social catastrophes–Elevate the confidence level of drilling each well productively and safely

Some notable features to include in this integrated environment are:–Automated collision avoidance–3-D visualization with powerful viewing features–Graphically interactive 3-D well planning with modifiable and fixed constraints–Links to petrophysical, geological, survey and drilling data

Today there is not yet a system that combines the full 3-D description of reservoir shape and properties with modern directional drilling software. Case studies presented in this paper will demonstrate the need to commercialize and further develop such a system.

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A New Approach to Mechanized Tubular Handling and Running as a Safe and Cost Effective Alternative
Authors: Kinzel Holger , Lorenz Jörg
Published: December 2007

More than 30% of total rig time is spent on drillstring tripping and casing and tubing running operations. Tripping operations always have been the cause of heavy accidents. The easiest way to reduce the safety hazard is to reduce the number of people involved in unsafe operations. The number of people involved in manual operations on the rigfloor is directly related to the safety of the drilling rig's operation. The reduction of total personnel on board is significant for the costs. This requires the mechanization of processes now done manually.

Traditional automation concepts often required the complete re-design of rig components such as power tongs and handling equipment. Even derrick structures had to be modified to fulfill the requirements of a completely automated process. This made several of these technically interesting concepts very expensive and not many of them were actually put into operation.

A new approach to rig mechanization is based on existing technology. System components with proven designs such as hydraulic power tongs for drillpipe, tubing and casing running are modified for mechanical and remote controlled operations and are combined in a modular system.

This system includes a new technical solution to move the hydraulic power equipment towards the string and to pull it back into park position. The device is based on zipping chains guiding the equipment on a pre-defined line. It can be attached to any existing derrick structure in an elevated position not consuming any valuable rig space.
A New Environmentally Safe High-Temperature, Water-Base Drilling Fluid System
Authors: Thaemlitz Carl , Patel Arvind , Coffin George , Conn Lee
Published: December 2007

A new, environmentally safe water-based polymer system has been developed for drilling applications with temperatures up to 232°C (450°F) and high pressures. The system components are newly developed synthetic polymers that do not contain chromium or other environmentally harmful materials. These new synthetic polymers are designed to perform specific functions at high temperatures and the innovative designs of these thermally stable polymers allow for the use of a minimum number of products in the formulation of high-temperature fluids.

The new system consists of two basic polymeric components for rheology and filtration control at high temperatures. High-temperature fluid formulations are greatly simplified utilizing this new system, with only the two polymeric components being required, along with a pH control additive, weight material, and small amounts of clay for filter cake quality. This simplicity is a significant advantage over "traditional" high-temperature systems, which normally require use of a large number of additives to control or limit the effects of thermal degradation.

The new system may be formulated with fresh water or sea water, providing flexibility for a variety of drilling environments. Excellent resistance to common contaminants, such as calcium and magnesium hardness and solids accumulation, is another important characteristic of this new system.

This paper will review the previous state of the art with respect to high-temperature, water-based muds and will generically discuss the unique chemistry of the newly developed polymer system components. System formulation and application will be discussed.
Drilling Through Mature Production Zones
Authors: Kenney N. R , Kilchrist Joseph
Published: December 2007

This paper is a case history which describes the six wells of a drilling program fostered by 3-D seismic data. The challenge of this project was significant, and the early wells did not reach target depths due to stuck pipe in depleted zones. Importantly, success was realized on the final three wells through the creative application of existing technology. The ultimate success of this drilling program may be attributed to the application of real time dynamic filtration technology on the drilling fluids of the successful wells.
The Role of a Worldwide Drilling Organization and the Road to the Future
Authors: Boykin G. F.
Published: December 2007

After struggling for the past few years with the question "How can we get the highest return for our drilling expenditures?", major operators have arrived at very different answers. Some have responded by moving the drilling function to business units, some by retaining a mixture of centralized and decentralized drilling staffs, and some by outsourcing the function almost entirely.

The purpose of this paper is to describe why one major operator has chosen to keep drilling management as one of its core competencies, and how it continues to use a centralized drilling group to meet its exploration and production customers' needs. Also discussed is the deliberate strategy employed by this operator to meet the challenges posed by the changing exploration and development environment. This strategy included elements to manage people, business and technical processes, and to ensure that the drilling organization captured and shared its experience. This paper describes this strategy, the organization's successes and remaining challenges, and how this organization plans to address these challenges.
The Destruction of PDC Bits by Severe Slip-Stick Vibration
Authors: Fear M. J. , Abbassian F. , Parfitt S. H. L. , McClean A.
Published: December 2007

Surface mud logging systems have detected a severe form of torsional vibration that causes rapid destruction of polycrystalline diamond compact (PDC) drill bits. These failures can occur when combining a limber bottomhole assembly (BHA) with a PDC bit lacking some form of anti-whirl stabilisation. On the basis of experience to date, these vibration-induced failures occur only in larger hole sizes.

This paper describes the nature of these bit failures, their dependence on operating conditions, and practical recommendations for avoiding failure. Experience from one operation, in which revised drilling practices and bit selection criteria eradicated the failures, will be presented.