bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Evaluation Results of New Clay Stabilizer in the Appalachian Area
Authors: Baltz T. H. , Himes R. E. , Dalrymple D.
Published: December 2007

Formation damage in the vicinity of the wellbore is a major cause of low productivity, and the difficulties involved in removing the damage translate into a significant number of wells that do not respond satisfactorily to remedial treatment. This damage is usually the result of fines migration which is triggered by the introduction of foreign water. The migrating fines tend to lodge in constrictions in the formation flow channels where they severely reduce production.

Clay stabilizers have been used to solve this problem for several decades. Cationic organic polymers (COPs) have been the most popular stabilizers because of treatment longevity and effectiveness in moderate to high permeability formations. Most producing formations in the United States, however, do not have moderate to high permeabilities but are classified instead as "low" permeability.

A new clay stabilizing additive has been developed specifically for low permeability formations typical in the Appalachian basin. This low molecular weight chemical is shown to be effective in rock matrices with permeabilities as low as 0.015 md. Other popular clay stabilizers with higher molecular weights are less effective in preventing swelling and migration of clay in formations having permeabilities below 30 md. Additionally, permeability damage can result when these relatively high molecular weight polymers are injected into low permeability formations.

Data are included from laboratory core tests using the low molecular weight clay stabilizer. The encouraging results of these laboratory tests is supported by field production results in the Appalachian basin. The field data include the results of fracturing, acidizing, and other operations, all of which are tabulated and discussed.
Application of Deep Diving Systems in Offshore Operations
Authors: Young K.G.
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

This paper reviews current offshore operations around the world which involve the use of tethered, manned submersibles to support deep diving operations.

It discusses the evolution of simple underwater transport vehicles to the relatively sophisticated semi-mobile hydraulic tool equipped, life support capsules which have found applications in offshore petroleum, salvage and underwater construction. A variety of systems have been developed during the past few years to meet the many and various needs of the offshore diving industry.

The conclusions reached by this paper are that the current utilization of diving systems in the support of deepwater offshore work has resulted in increased efficiency, reduced costs and much safer operations.

Introduction

This paper provides a brief review of deep diving systems which have current applications in the support of offshore petroleum recovery, salvage operations and underwater construction. Its primary focus is on "tethered" or surface supported diving bell systems capable of "looking out" 1 / divers rather than submarines (with or without diver lockout capabilities), simple observation bells or open bottom decompression rest chambers. To date, the tethered diving bell systems with a diver lockout capability, have enjoyed a more active commercial offshore utilization than other types of submersibles, due to the nature of current offshore technical and economic requirements.

The tethered diving bell is an ancient invention.
Hydrodynamic Modeling of Wellbore Hydraulics in Air Drilling
Authors: Adewumi M. A. , Tian S.
Published: December 2007

Optimal design of any drilling program requires a good knowledge of the wellbore hydraulics. For conventional mud drilling, established techniques are available for formulating some understanding of the associated wellbore hydraulics but this is not the case for air drilling. It is a fact generally acknowledged that the wellbore hydraulics involved in air drilling presents a distinct problem from those associated with mud drilling. A systematic study of this problem especially utilizing fundamental approach is lacking. This study addresses this important problem using a fundamental hydrodynamic multiphase flow model. The model incorporates the fundamental physics involved in the pneumatic transportation of solid cuttings in the drill string-wellbore annulus. This model forms the basis for a predictive tool for the optimal lifting velocity, an essential ingredient in the optimal design of the air drilling program.

Air drilling program design must rely on the a priori knowledge of the basic design parameters such as how much air is required for optimal lifting of the drill cuttings, pressure drop as a function of drilling rate, etc. Drilling engineers often experience frustration due to lack of models with adequate predictive capability to help them answer these basic questions. Available correlations are, at best, gross approximation and more importantly, they fail woefully to account for the physical phenomena that are observed in pneumatic conveying involved in air drilling such as choking, clumping, etc.

We present a fundamental wellbore hydraulics model based on the understanding of the physics involved in the pneumatic transport of solid cuttings in the the drill-string/wellbore annulus. Extensive parametric analysis of the system is performed to validate the viability of the model as a predictive tool. Its capability as a design and scale-up tool is also investigated by simulating field conditions. The model is demonstrably capable of predicting the pressure drop profile in the annulus under various simulated drilling conditions. In addition, results demonstrate the capability of the model in being able to predict a number of phenomena that are associated with lifting cuttings out of the hole during air drilling. The model possesses scale-up capability.
Diamond-Enhanced Hammer Bits Reduce Costs-per-Foot and Directional Problems in Southwestern Pennsylvania Oriskany Wells
Authors: Weller T. F. , Baum G. A. , Muncy W. H.
Published: December 2007

A case history of the drilling practices on southwestern Pennsylvania Oriskany wells demonstrates how the use of diamond-enhanced hammer bits have reduced costs per foot and directional control problems.
Pattern Recognition Applied to Dynamometer Cards
Authors: Keating J. F. , Laine R. E. , Jennings J. W.
Published: December 2007

Petroleum engineers have traditionally used downhole dynamometer cards1 to diagnose the operation of sucker rod pumps. Specific problems have characteristic cards. The analysis procedure typically compares the unknown card with a library of known cards.

At least one expert system2 successfully diagnoses sucker rod pump problems. EXPROD uses a statistical pattern recognition scheme to obtain a diagnosis.

This paper gives a numerical pattern recognition scheme "NUPRO" that correctly diagnoses 100 unknown cards from a library of 37 known cards.
Variables Affecting Restored-State Determination of In-Place Oil
Authors: Lewelling Henry , Grubb W.E.
Published: December 2007

One of the important functions of the petroleum engineer is the volumetric analysis of the reservoir for an estimate of in-place oil. The reliability of the estimate is a joint function of the accuracy of basic data used and of the correctness of application. Frequently, basic data are obtained from laboratory determinations of porosity and interstitial water saturation. It follows that errors in laboratory measurement may have a serious effect on reservoir evaluation. A better understanding of the methods used, of the variables that affect it, and of consistent variations that tend to yield high or low results will allow the laboratory worker to produce more accurate values. Similarly, a better understanding on the part of the engineer will permit him to use the data more intelligently so that unavoidable errors may be corrected rather than compounded, and so that an increased reliability of reservoir evaluation may result.

This paper presents the results of investigations of variables which may lead to errors in some standard porosity methods, and in the restored-state [disc] determination of interstitial water. Variables of preferential wettability, clay hydration and gas adsorption are shown to be interrelated in their effects. Additional variables related to equipment, technique, capillary pressures, fluid phases and calculation procedures are considered. It is shown that a report would more properly present porosity available for hydrocarbon storage than simply porosity and interstitial water content. Data obtained statistically from a quantity of restored-state and routine core analysis work are offered as supporting evidence. The variables are each treated individually, so that each may be understood separately, as well as in its interrelationship with others.

Introduction

The restored-state concept has been widely utilized as an indirect approach to petroleum reservoir evaluation. The term denotes a laboratory simulation of reservoir processes of oil accumulation and production in a sample of reservoir rock. Determination of interstitial water has been a primary concern of restored-state work during its relatively short life. Publications have dealt with variously devised interstitial water methods and modifications of methods. In one particular aspect much of the reported work has been somewhat idealized in that implicit assumption has been made that porosity measurement is not a problem as associated with determination of interstitial water.

In this paper, consideration is given variations between some usual porosity methods which are utilized in routine core analysis and restored-state work.
Simulation of Gas Injection Processes in Gas-Condensate Reservoirs Using a Binary Pseudo-Component Representation
Authors: Goldthorpe W. H.
Published: December 2007

A method is presented for simulating gas injection processes in gas-condensate reservoirs below the dewpoint using a binary pseudo-component representation. The fluid phase behaviour (including mixing with injection gas) is first modelled with an equation of state using a large number of components. A lumping scheme is then found that allows a projection into a binary pseudo-component subspace which minimises the variation in the mass fraction of each pseudo-component in the vapour phase during liquid re-vapourisation. These two pseudo-components are then used in the PVT representation. The manner in which inverse lumping is performed to obtain separator products is described. The third SPE comparative solution project is used to illustrate the application of the method with a conventional black oil simulator, however the procedure is equally applicable to limited compositional or two component K-value simulators.
Development, Application, and Utility of Compact Wellhead Systems
Authors: Courtney G. L.
Published: December 2007

The use of compact wellhead systems, with the ability to hang multiple casing strings from a single forging, has improved drilling efficiency in the Gulf of Mexico, Offshore Louisiana. This recently patented dual hanger system is being used to substantially reduce the drilling cost and improve safety.

Both an 18-5/8″ OD (Outside Diameter) conductor casing assembly and a 13-3/8″ OD surface casing assembly are installed through the diverter assembly and supported within the dual hanger casinghead prior to any disconnection and removal of the diverter assembly. An upper compact housing is then utilized and both a 9-5/8″ OD protective casing assembly and a 7″ OD production casing assembly are installed through the BOP (blow out preventer) assembly prior to any disconnection and removal of the BOP assembly.

Compact wellheads have been utilized on several development drilling projects with standardized casing programs for several reasons: –Time and money were saved as a result of the reduction in BOP nipple up time.–Significant safety advantages were realized; the use of mandrel hangers resulted in immediate sealing of the annulus in an area where annular gas flow is prevalent.–Casing cutting can be eliminated, thereby, minimizing production shut-in time during PWD (Produce While Drilling) cycles.

As of January 1, 1989, Shell Offshore Inc. (SOI) has installed 40 compact wellhead systems on two recently drilled development programs. The total cost savings directly attributable to this system, to date, is $511,000. This paper will address the pros and cons using these wellhead systems, modifications implemented, and review operating experiences to date. In addition, suggestions are presented for further development and use in both low-pressure and high-pressure applications.
Minimized Hauloff While Drilling in a Zero Discharge Area
Authors: Sanders J. M.
Published: December 2007

Chevron U.S.A. Inc. is currently drilling a 23,500 ft. wildcat five (5) miles off the coast of Mississippi, in a zero discharge area. The design of this well included a 17-1/2″ hole to 16,500 ft., which would produce record waste hauloff volumes. A cost saving approach was taken in an effort to minimize the impact of drilling a well of this size in a restricted area.

The approach involved modifications made to the rig and operations to reduce the complexity and expense of waste handling. The primary modifications are as follows: (1)Modify a submersible type rig to store deck drainage in the columns omitting the need for a permanent barge moored on location for waste collection.(2)Upgrade the rigs solids control equipment to reduce dilution volumes.(3)Utilize a dewatering unit to process mud and reuse the water phase in the mud system.(4)Design cuttings transport system, barge and chute, to move cuttings without the use of water.(5)Conduct operations using deck drainage and gray water in the mud system to minimize waste buildup.

This paper summarizes the design and operation of a minimum hauloff waste handling system for drilling in a zero discharge area. Included are descriptions of rig and operational modifications performed to reduce cost. Resulting data has shown cost savings to be in the 50% range. The information and concepts may be beneficial to drilling operations conducted under similar circumstances in other area.
A Cementing Job Preparation Advisor System
Authors: Wolsfelt G. C. , Roger C. , Fenoul R.
Published: December 2007

This paper reflects our experience of the design and use of a new expert system for Cementing preparation aid.

The quality of casing cementing is important in ensuring the long lived productivity of a well. It is therefore essential to ensure a good preparation of this delicate job. The know-how of the trade completed by the calculations to be taken into account are gathered in one same system which offers to the user an optimized solution with respect to his restraints.

This expert system called CIMENTEX is intended for the field operators and allows us to pass on the rules of the art and to improve it with field experience, by feedbacks.

The aim of this software is also to give rise to the user's reflections and critical remarks which are necessary to enhance the cementing technique.

This is made possible because of the time saved on preparation and the opportunity to perform the same inquiry over again very quickly.

This expert system was first validated in the Drilling-Completion central services then in three subsidiaries of our Group. It is now operational in its initial aid release fot the preparation of production and intermediate casing cementing.
PDC Bits Proved Effective in Drilling Severely Depleted Sands in the Gulf of Mexico
Authors: Hanna I. S. , Hollister K.
Published: December 2007

Drilling severely depleted sand zones is one of the most difficult tasks for drilling personnel. Problems such as differentially stuck pipe, complete loss of circulation, excessive torque and drag, and hole washouts are common and have forced many operators to abandon the development drilling of otherwise commercial fields. Depleted sand zones have also prevented deep drilling to explore the promising hydrocarbon reserves which exist beneath them.

This paper describes the techniques used to successfully drill through a series of depleted sand zones containing hydrocarbons with as much as 4,720 psi (330 kpa) overbalance differential pressure at 9,987 ft (3,276 m) true vertical depth.

By using the proper PDC bit which incorporates recent advancements in cutter technology combined with optimized hydraulics, and good mud filtrate and lubricity properties, Mobil demonstrated that it is possible to successfully drill through a series of abrasive and depleted sand zones. The high ROP and long life of the PDC bit reduced both the drilling and tripping time compared to conventional roller bits used to drill the offset wells. As a consequence, exposure time was reduced, and the surge and swab pressures imposed on the depleted sands were minimized, thus preventing lost circulation in the depleted intervals. Additionally, a savings of over $ 250,000 was realized in the 12-1/4" (311 mm) interval of a single well.
Treating Brackish Water For High Pressure Boiler Makeup For Thermal Flooding By Continuous Ion Exchange: A Case History At Coronado Oil Company
Authors: Higgins Irwin R.
Published: December 2007

A CHEM-SEPS type continuous ion exchange water softening plant manufactured by Chemical Separations Corporation of Oak Ridge, Tennessee, is operating in the steam flood oil drilling operation of the Coronado Oil Company at Red Springs, Wyoming. This continuous system, invented by Irwin R. Higgins, has found wide application in a variety of water treatment and chemical process applications including sea water softening, municipal water softening, industrial waste cleanup, water and waste demineralization and mineral recovery operations in the nuclear, fertilizer and plating industries.

The Coronado well water supply is brackish, having a hardness content of 1000 parts per million (ppm) and sodium salt content of 1000 ppm. The continuous ion exchange system softens the water from 1000 ppm to less than 1 ppm, a 99.9% removal. The softened water is fed to a once-through high pressure boiler operating at 700F, 2500 psi.

Ion exchange resin is regenerated with saturated salt solution. Salt consumption is approximately 100% in excess of the equivalent hardness removal. Correction of initial mechanical problems now allows 24 hour operation with 16 hours unattended. A fixed - bed polisher is used to protect from misoperation and feed fluctuation. The resin is strong acid, polystyrene type. The attrition rate is approximately 20% per year and no loss of exchange capacity of the resin has been experienced during two years of operation.

The CHEM-SEPS continuous system offers substantial savings over stationary bed equipment including greatly reduced resin inventory and a 2 to 3 times reduction of chemical consumption. Further brackish water studies using CHEM-SEPS type continuous ion exchange indicate successful use of brine waste as regenerant chemical which should eliminate chemical cost entirely in the future.
Narrow-Band Infrared System For Detecting Oil In Water At 3.42 +/- 0.3 mu
Authors: Salkowski Martin J. , Jackson Meryl R.
Published: December 2007

The manuscript is missing Figures 11 to 22.

This paper describes a narrow-band infrared concept for monitoring oil in water. The instrument based on this concept is the culmination of a total research effort that consisted of a literature survey, prototype studies, construction of an engineering model, engineering evaluations in the laboratory and in the field at a refinery, and finally redesign of the field prototype based on the field data. The basic guidelines for this research effort were:The detection system must operate continuously and require only water, sample, and electrical power.The detection system should have few or no mechanical parts.The detection system must have equal sensitivity and response for oil in fresh, brackish, and salt water samples.The detection system may be presented with high levels of secondary contamination; thus the technique should minimize the effect of secondary contamination on the total signal.The detection system should be specific to oil.The detection system should be self-calibrating.
Rocky Mountain 1 Underground Coal Gasification Test: In-Situ Coal Conversion Using Directionally Drilled Wells
Authors: Gash B. W. , Hill V. L. , Barone S. P. , Martin J. W.
Published: December 2007

Rocky Mountain 1 (RM1) was a joint industry-DOE underground coal gasification (UCG) test conducted near Hanna, Wyoming for 102 days during 1987-1988. Medium radius directional drilling was used to establish a path in the coal seam for injection of steam-oxygen. Based on RMl results, costs for UCG gas produced via directionally drilled wells have been developed. Early results indicate that RMl was performed in an environmentally acceptable manner.
BOMEC: A New Artificial-Lift Design Method for Producing Heavy Crudes
Authors: Brunings C. A. , Castillo V.
Published: December 2007

The need for CORPOVEN, S.A. affiliate of Petroleos de Venezuela, S.A. to obtain a model for use in the evaluation of pumping units and down hole equipment in heavy oil wells, resulted in the development of an applicable design and optimizati on technique. All existing models are based on parameters related to wells and equipment for 1ight and medium crudes. As Venezuela conti nues to produce 1 arge quantities of non conventional heavy oil, the need for additional modelling is emphasized.

This paper presents the results of adaptations and improvements made to an existing conventional model, making it applicable to heavy crudes. The model presented (Bomec) is based on correlations generated from traditional sucker rod design methods; however, it includes several field factors (friction, flotability, etc) especially suited for heavy and extra-heavy crudes. A comparison was made with other models available in the industry, and very favorable results were obtained.

Application of traditional correlations to heavy crude installations results in an over or under-design of pumping units. This causes an increment in production costs due to increased horsepower requi rements, maintenance and capital investment. The Bomec model is applicable for any type and geometry of pumping unit, electric or gas motor, devi ated or straight well, anchored or unanchored tubing, API rods and any type of pump. Also it simulates producti on through the casing-tubing annulus.
Production Technology
Authors: Milliken J. , Miller G. , Baldwin K. W. , Fagerstone D. , Dixon G. , Brockman J. , Riggs L. M. , Batch G. R. , Begland M. B. , Lindley T. M. , Laine R. E. , Cole D. G. , Jennings J. W. , Miquel F. , Haukjem M. , Skiftesvik P. K. , Keating J. F. , Takacs G. , Hagood D. S.
Published: December 2007

The Production Technology Session is designed to allow the discussion of and dissemination of information about technical innovations and solutions in production engineering that are of immediate practical use but do not warrant a full-scale paper. Each subject is presented in a five to seven minute period with a discussion period of six to eight minutes. A wide range of subjects is encompassed in the session. Abstracts of the presentations follow.
Fracture Conductivity Impairment Removal
Authors: Norman L. R. , Hollenbeak K. H. , Harris P. C.
Published: December 2007

Extensive and detailed research has been accomplished by previous investigators to characterize formation damage caused by various fracture fluid types. Using a simplified method developed specifically to study impairment removal, a body of comparative data was generated to show the tendency of dynamically-formed filter cakes to clean up from formation faces. Data have been developed for most aqueous fracturing fluid types at temperatures from 100 to 300°F.

Of the fluids tested, foams were quickest to clean up followed by uncrosslinked gels and crosslinked fluids, respectively. High viscosity foams produced much thinner filter cakes than non-foamed fluids. Of the crosslinked fluids, borate-based systems tended to clean up more rapidly than systems crosslinked by other metals. Flowing oil stopped all fluids tested from cleaning up, including borates. At temperatures above 250°F, crosslinked fluids exhibited enough thermal breakdown to suggest that damage due to polymer filter cake may be less severe at this temperature.

Field studies after the fracture treatment on five wells showed a high percentage of unrecovered gelling agent residue, suggesting the need for some method to clean up polymer filter cake left in the formation. A special solvent system was developed to remove crosslinked fluid filter cakes. Field results using the filter cake solvent are presented on 33 wells. On 12 of the wells, gel analyses of returns revealed broad ranges of gel content, suggesting that contact with the remaining filter cake is a limiting factor in some cases.

This paper presents a body of data to assist the stimulation planner in selection of fracturing fluids and presents a system to help clean up gel depositions.
Reduction of Oilfield Production Wastes Using Dry Cake Filters
Authors: Townley D. , Bergman R. J. , Goldman W. A.
Published: December 2007

A dry-cake filter has been successfully tested to reduce the volume of two oil field waste streams. In the first application, filter backwash containing solids up to 650 mg/kg and suspended oil up to 190 mg/kg was filtered to 25 mg/kg solids and 2 mg/kg oil. The objective of the test was to eliminate the use of production pits as settling ponds. In the second application, sand dumps from a production wash tank were successfully filtered, again to eliminate dependence on production pits.

The dry-cake filter uses a diatomaceous earth or perlite (DE) precoat on wire-wrapped screen filter elements. Additional DE is used as body feed to the influent stream during filtration. The backwash cycle, triggered by differential pressure, uses air or field gas to dry the cake and then bump it off the wire screens into a disposal hopper. The total amount of DE added in the precoat and body feed can be as low as 30% by weight of the solids to be filtered.

The dry filter cake contained 40% solids, 10% oil, and 50% residual water, and had a bulk density of 0.65 g/cc [650 kg/m3]. Environmental testing showed the filter cake to be nonhazardous under current EPA regulations. Disposal of the filter cake is compared to disposal of pit bottom sludge.
Completion Planning for Elimination of Sand Production in Thinly-Bedded Aquifer Gas Storage Wells
Authors: Toney J. B. , Morgan J. A. , Barnette J. C. , Bielecki D. L.
Published: December 2007

Sand and fines produced during withdrawal from thin, friable beds in aquifer gas storage reservoirs abrade and constrict production hardware, damage seals, and eventually fill the wellbore, leading to costly cleanout and repair operations. The chief cause of sand production and its subsequent reduction of injection and withdrawal efficiency is a high-pressure drop across the completion.

Completion planning to minimize pressure losses is difficult because it must account for fluctuating pressures, relative permeabilities, and reservoir flow characteristics across a wide range of operating conditions. In the case of anisotropic formations, planning and evaluation become still more complicated because individual rock and fluid properties deviate substantially from the collective average. A new type of high shot-density perforator simplifies planning and execution of new completions by shortening the distance fluid must travel across the lowest permeability of any given bed.

The perforator provides a unique geometrical pattern of perforations along the axis and around the radius of the wellbore which also minimizes pressure-dependent problems associated with variable rock strength. Downhole video photography confirms that sand influx has been averted in a well completed with this perforator after two injection and withdrawal cycles and that high shot-density did not damage casing. The completion technique circumvents the high costs of plastic consolidation used in other wells or other remedial techniques that were considered.
Use of Digital Electronics to Improve and Monitor Efficiency of Low-Speed Integral Gas Engine/Compressor Units
Authors: Thomas T. W.
Published: December 2007

Mobil Exploration & Producing U. S. Inc., Denver Division, recently tested a new electronic system that controls engine operating parameters and continuously monitors fuel and throughput efficiencies. This was done in an effort to reduce the costs of operating older reciprocating engine/compressor units, utilizing an investment level that was economically justifiable. This digital electronic control/monitoring system has successfully demonstrated benefits in reducing fuel consumption, reducing maintenance requirements, and detecting mechanical defects at very early stages.
Practical and Theoretical Aspects of Well Testing in the Ekofisk Area Chalk Fields
Authors: Snow S. E. , Brownlee M. H.
Published: December 2007

This paper describes pressure transient testing and analysis procedures used in the Ekofisk Area chalk fields. These chalks consist of low permeability, thick, naturally fractured formations which are stimulated by pseudo limited entry, massive acid fracturing. Transient tests are interpreted in real time utilizing an on site portable computer. Test interpretation requires the use of spinner and/or separator rates for normalization, superpositioning, and pressure derivative data. The induced fracture systems are complex, having multiple fractures which are partially penetrating with limited perforation height and other non-ideal characteristics. It has not been possible to isolate the character of these nonideal conditions through pressure transient analysis. Instead, an equivalent fracture system which behaves similar to the actual system is identified during the test interpretation. Using the eqivalent fracture system concept, it has been possible to accurately forecast production, monitor well performance, evaluate the need for restimulation, and optimize completion and stimulation designs.
Pressure Falloff Analysis for Steam Injection Wells in a Low-Permeability Reservoir With Steam-Induced Vertical Fractures
Authors: Ambastha A. K. , Kumar M.
Published: December 2007

This paper presents results of pressure falloff analyses for three cyclic steam injection wells in a low-permeability (<1 md), heavy oil, reservoir with steam-induced vertical fractures. In one of the wells, a falloff test was also conducted after brine injection. The objectives of these tests were to estimate fracture and reservoir parameters and swept volume. The study also demonstrated the influence of wellbore thermal and fluid flow effects on pressure falloff test results in steam injection wells.

Results show that a good estimate of kxf2 can be obtained (where k is effective formation permeability and xf is fracture half-length). Approximate values of k and xf were also obtained. However, the estimate of swept volume using the pseudosteady-state analysis yielded unrealistically large swept-region width. This may be caused by the short steam injection time prior to conducting the falloff tests. Pressure falloff tests in all wells were significantly influenced by wellbore thermal and fluid effects which usually lasted for 10 hours or more. A new procedure is outlined to determine the period of wellbore effects.
Automatic Matching Type Curves for Pressure Transient Analysis
Authors: Duong A. N. , Foster G. A.
Published: December 2007

The type curves using pressure/pressure-derivative ratio (PDR) was recently introduced so that the type-curve matching requires the movement of field data only in the horizontal direction. This improvement not only facilities the type-curve matching, but also increases the reliability of analysis results. However, the uniqueness of the results from a type-curve match is still the major concern.

This paper presents a new plotting technique for type curves and field data plot that will eliminate the movement of field data in both directions. The horizontal scales on both type curve and field data plots are fixed by the use of the time/pressure-derivative ratio (TDR) as a parameter in constructing the type curves and field data plot.

The paper concludes that using the proposed type curves with PDR and TDR as parameters will give the automatic alignments on both vertical and horizontal scales. Thus, the movement of data for type-curve matching is not needed. The wellbore storage constant, cD, can be read directly on the horizontal axis at PDR of 1.

The work of this study is limited to the type curves for wells in homogeneous radial systems with wellbore storage and skin.
Detecting Country Risks to Oil Companies in Lesser-Developed and Newly Industrialized Countries
Authors: Hallmark T. L.
Published: December 2007

This paper examines the current status and function of oil industry-specific country risk assessment and identifies the existing level of threats to oil company investment in 15 lesser-developed and newly-industrialized countries. It is argued that relatively few countries are "off limits" to foreign oil companies and that risks to investment are determined more by host-country legislative or policy decisions than by serious macro-level or systemic disruptions. The 15 countries are then rated and ranked according to an analytical scheme utilizing 23 political, economic, legal and industry-related factors.
A New Biopolymer for High-Temperature Profile Control: Part II—Field Results
Authors: Sampath K. , Jones L. G. , Strom E. T. , Phelps C. H. , Chiou C. S.
Published: December 2007

High temperature polymer formulations were successfully used to modify water injection profiles in the South East Bradley "A" Unit in Oklahoma. Injection profile logs show evidence of vertical sweep modification. Pressure fall-off tests show that areal sweep modification was also achieved. There was a strong oil production response to the polymer treatment. Incremental oil production during the first year following polymer injection was about 25,000 barrels, corresponding to about 0.8 barrels of incremental oil per pound of polymer injected. Production response is continuing.
Marine Construction In Cook Inlet
Authors: Nelson H.A.
Published: December 2007

Marine construction in Cook Inlet, Alaska is probably more difficult and more hazardous than in any other area in the world. Marine construction in Cook Inlet for the petroleum industry began 1960 with the construction of a gas transmission line across Turnagain Arm to bring gas from the Swanson River Field to the city of Anchorage. (See orientation map) This project is considered by most to be the pioneer project of Cook Inlet marine construction. Though Turnagain is not the worst location with respect to weather, tide and current, the lack of experience with these elements made this a very difficult project. Methods of coping with the hostile environment of Cook Inlet have improved steadily since that time and oil companies and contractors have all benefited from studying the efforts of predecessors.

CONSTRUCTION TO DATE

At the present time, there are eleven offshore platforms installed in Cook Inlet with seventy-five miles of pipeline installed to service these structures. (See orientation map)

Generally, production is being delivered about evenly to the east side of the Inlet and to the west side of the Inlet.] Production from six platforms is going eastward and production from five platforms is going westward.

All platforms, except one, are of the four-leg type. One unique platform, the Monopod, is a single leg type developed especially for Cook Inlet. This platform has proven to be particularly successful in fabrication and construction.

CONSTRUCTION PLANNED FOR 1968

The smaller 1968 program probably represents a breathing spell for the oil companies as there has been a tremendous investment in Cook Inlet and returns on investment are not yet fully developed.

COOK INLET MARINE CONSTRUCTION PROBLEMS

Marine construction is hazardous in any locale as marine construction is particularly vulnerable to uncontrollable factors of weather, tide and current.
How To Use a Noncantilevered Jackup for a Platform
Authors: Shetti B.
Published: December 2007

The object of the paper is to illustrate how a non-cantilevered jackup unit can make its drilling package more useful to reach unreachable wells of multi-well drilling platforms.
Drilling a Record Horizontal Well: A Case History
Authors: Brannin C. S. , Velser L. , Williams M. P.
Published: December 2007

During early 1989, Maersk Oil & Gas A/S, as operator for Danish Underground Consortium, drilled the first horizontal well in the Tyra field, offshore Denmark. Prior experience acquired during horizontal drilling operations in the Dan field enabled Maersk to establish ambitious objectives for well TEB-1, including: displacement at total depth of 10,000 ft [3050 m], horizontal section of 3,000 ft [910 m], with maintenance of a 20 ft [6,1 m] vertical tolerance throughout, cementation, with rotation, of a 6 5/8-in [168,3mm] production liner across the horizontal completion interval.

To achieve these objectives economically, Maersk implemented a well profile with both long and medium-radius characteristics; steerable medium-radius angle-build drilling motors; thermally-stable synthetic diamond drill bits; and the most recent advances in liner hanger technology.

The unqualified success of drilling operations on well TEB-1 has confirmed the viability of precisely placed, high displacement, horizontal completion intervals as an economical alternative to more conventional field development strategies.
Field Comparison of Medium- and Long-Radius Horizontal Wells Drilled in the Same Reservoir
Authors: Hassen B. R. , MacDonald A. J.
Published: December 2007

Two horizontal wells, one with a medium radius angle build rate and the other with a long radius wellbore have been drilled into the same oil bearing sandstone in the Province of Alberta, Canada. The wells were drilled as development wells to test the concept of minimizing water coning in a heavy oil reservoir by placement of a horizontal wellbore at maximum distance above the oil/water contact. Most published case histories reflect the common practice of using only a single preferred curvature for wells in a specific area. However, two different curvatures were used in this area which provides the opportunity to make a field comparison of the two drilling methods. Although the choice of Long Radius versus Medium Radius method is distinctive in many applications, both drilling methods appear viable for horizontal wells in this area.
Kick Prevention, Detection, and Control: Planning and Training Guidelines for Drilling Deep High-Pressure Gas Wells
Authors: Hornung M. R.
Published: December 2007

Conoco has developed generalized planning and training guidelines for well control on deep, high-pressure gas wells. These guidelines include a thorough review of gas behavior, causes of kicks, pressure indicators, and kick indicators as they are applied to high-pressure gas wells. The guidelines also emphasize the fundamentals associated with constant bottomhole pressure methods of well control. After the basic principles are reviewed, the characteristics of oil base mud are discussed. These characteristics are then related to all of the basic principles. Following this review, there is a practical example based on experiences Conoco had on a deep, high-pressure gas well drilled with oil base mud. Finally, there is the development of procedural and equipment requirements that are the result of having systematically addressed well control principles for deep, high-pressure gas wells.
Plotting Sonic Logs to Determine Formation Pore Pressures and Creating Overlays to Do So Worldwide
Authors: Weakley R. R.
Published: December 2007

The determination of formation pore pressures from log derived properties is a highly used and accepted practice in the Gulf of Mexico. Such determinations in other parts of the U. S. and the world have generally been very difficult, if not impossible, in many instances. Failure to do so, in most cases, has led to extreme drilling difficulties or unsuccessful wells. Much of the time, high pressure shale sections have been misinterpreted as chemically sensitive formations requiring exotic mud chemistries and resulting in needless excessive expense.

We have developed a technique for the determination of formation pore pressures from sonic log trends which is universally applicable. This approach has been utilized in numerous locations around the world with great success. The process will be demonstrated in detail and several examples of results thus achieved from wells around the world will be presented.

In conjunction with this pore pressure determination process, a simple means of creating a pore pressure overlay to interpret the data will be demonstrated. This aids in speed of determinations and simplifies the analysis somewhat.

Before an estimation of anticipated pore pressures to be seen in a proposed drilling prospect can be made, determinations of actual pore pressures seen in offset wells is essential. These pore pressure determinations are therefore essential to the efficient an successful drilling of a well, and this technique enables one to make them.
Formation Damage Prevention During Drilling and Completion
Authors: Reed M. G.
Published: December 2007

The possibility of causing formation permeability damage exists during many operations throughout the life of a well. This paper deals with formation damage in only the earliest stages, i.e., during drilling and completion. Drilling fluid is the first non-indigenous fluid to contact the formation and thus, it provides the first opportunity for causing permeability damage. Other potentially damaging fluids that frequently contact the formation during drilling and completion are cements, perforating fluids, gravel packing fluids, and kill fluids.

Most drilling fluids are designed to de-flocculate clays and other fine particles in the wellbore, which is opposite to what is desirable in the formation rock. Therefore, filtrate invasion is potentially very damaging to the rock in the near-well area. Potentially damaging filtrates are also lost to the formation during well completions. Permeability damage frequently extends a few feet into the formation which makes it difficult to remedy. Therefore, damage prevention is very important.

Damage prevention is best accomplished by both minimizing filtrate invasion and the detrimental effects of invasion. While both are important, the latter is more practical because total elimination of filtrate invasion is virtually impossible. Water-based drilling and completion fluids can usually be made non-damaging by assuring that (1) they contain an adequate amount of salts, especially potassium salt, (2) they have a pH lower than about 9.5, (3) they do not contain materials that form precipitates on contact with formation water, (A) they contain a minimum amount of de-flocculants, and (5) completion fluids are clean. Laboratory flow tests using formation rock and reservoir fluids are useful for maximizing efficiency and effectiveness in the fluid design. Maximizing productivity of a damage susceptible well comes about only through a concerted effort to prevent formation damage during the life of the well, especially during drilling and completion.
The Design of Sucker Rod Pump Systems
Authors: Jennings James W.
Published: December 2007

The complete design of a sucker rod pumping system is an involved trial and error process. An "optimum" design requires that the engineer specify pump size and type; rod string size, taper, and material; surface unit type and size, gear box rating, beam rating, and stroke length; and prime mover type and size. The procedure requires that the engineer first assume an appropriate combination of pump, rod, unit, and prime mover and then perform calculations which lead to refining that initial assumption. This paper is intended to be a review of the several techniques commonly used to solve the problem. The author has taken the liberty to introduce several improvements to these techniques that have become apparent over the past several years.

As a minimum, the following information is required to start the design procedure:1

Fluid level Pump depth Pumping speed Length of stroke Pump plunger diameter Fluid specific gravity Tubing size and whether anchored or not Sucker rod size and design Unit geometry

The next step of the design procedure requires, as a minimum, the determination of the following operating characteristics of the design selection:

Plunger stroke Pump displacement Peak polished rod load Minimum polish rod load Peak Torque Polished rod horsepower Counterbalance effect
A High-Pressure Wellhead Lubricator
Authors: McKinney Howard E.
Published: December 2007

Published in Petroleum Transactions, AIME, Volume 195, 1952, pages 261–264.

A high-pressure wellhead lubricator has been developed to facilitate telemetering electrical measurements from subsurface reservoirs to the surface with the well under normal flowing conditions.

The field unit in use at the present time employs a 5/16-inch-diameter, single-conductor armored cable and is to be used in wells with surface pressures up to 5,000 psi. It has a pressure sealing element that maintains a continuous and absolute seal around the cable as it enters or leaves the tubing at speeds up to 175 feet per minute. A cable injecting device is used which obviates sinker bars or weight sections on the instrument.

The development of instruments for securing physical measurements in pressure wells has been confined in the past to those instruments which would operate on a wire line and record the necessary measurements in the downhole instrument itself, of those which would operate on an electric cable in a well with the surface pressure killed by the use of weighted fluids or by the use of tubing plugs. In one case the accuracy of the measurements is questionable, and in the other the range of application is very limited.

Considerable work has been done by other interests to provide effective means to accomplish the necessary telemetering. The U. S. Bureau of Mines developed a wellhead lubricator prior to 1947 which permitted a 5/16-inch-diameter single conductor cable to be lowered into a well with a surface pressure of approximately 500 psi. This unit was used successfully in a number of tests in Oklahoma. A company which tests wells has recently offered on a service basis a wellhead lubricator with a 3/16-inch-diameter cable that reportedly operates up to 2,500 psi surface pressures. Each of the above operates on a staging principle to effect a seal. In both of these units some leakage of well fluid occurs when the cable is moved.

In order to provide the maximum flexibility in its use, the following parameters were established for the design of our high-pressure wellhead lubricator:An absolute well fluid seal up to 5,000psi surface pressures.Means for raising and lowering the instrument at speeds of at least 100 feet per minute.Provision for the instrument to enter and leave the well without disturbing the well flow or the reservoir conditions.A cable large enough to provide suitable electrical characteristics and suitable mechanical properties.