bluuebunny/crossref_metadata_2025 huggingface dataset:
Casing Design in Directionally Drilled Wells
Authors: Woodlan Bruce , Powell G.E.
Published: December 2007

Design of casing strings for directionally drilled wells requires that consideration for bending load be included with calculations concerning tension, collapse and burst. The nature of the bending load calculation is such that it cannot be incorporated into a nomograph, but instead, must be calculated by trial and error. THUMS Long Beach Co. uses a combination of graphs and calculating procedures to facilitate designing casing in highly deviated holes.

INTRODUCTION

THUMS (Texaco, Humble [now Exxon], Union, Mobil, Shell) Long Beach Co., field contractor for the City of Long Beach, Calif., was established in 1965 to develop that portion of the Wilmington field lying offshore Long Beach, Calif. Four landscaped drilling islands were constructed, in addition to a land-based drilling site, to drill an anticipated 900 wells. As of Sept. 1973, 676 wells have been drilled, with the majority having a maximum drift angle greater than 50 ° from vertical (Fig. 1). Three wells have been drilled to a maximum angle of 81 ° from vertical. When designing casing for deviated wells it is important that, along with the customary considerations, a bending load effect be included in the calculations. THUMS' wells generally build drift angle below the kick-off point (KOP) at 5 °/100 ft (16.4 °/100 m) of drilled depth to a predetermined maximum angle, hold that angle ('sail') to a point above the producing horizon, and drop angle at 2 ° ±/100 ft (6.6 ° ±/100 m) until the resultant hole angle is 45 ° or less through the producing interval. The following design procedure considers the most extreme conditions expected to be encountered in running and cementing casing in deviated holes.

MATHEMATICAL CONSIDERATIONS

Seven major areas of concern in casing design are commonly dealt with in directionally drilled wells. Each topic is discussed below with the applicable mathematical approach for each.Buoyancy1,3,6â?"Fluid in the hole when running casing strings can appreciably change the effective weight of the casing. This becomes important in calculations concerning weight supported at any one point:Equation 1Bending Load1,3â?"The buildup and drop-off portions of deviated wells cause a bending load to be introduced on the casing. This is the equivalent of adding weight to the string at a specific point.
Ranger Six, Case History of a Pool Originally Developed for Waterflooding
Authors: Wade James E.
Published: December 2007

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

This paper was prepared for the 45th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Ventura, Calif., April 2–4, 1975. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor 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.

Waterflooding has long been recognized as an effective means of secondary recovery; however, little emphasis has been placed upon the application of this method early in the productive life of an oilfield. This report presents a case history of the Wilmington Ranger Six Pool which was developed in 1965 and has been under waterflood since its initial development. Performance to date indicates average oil production per well has been sustained at rates more than four times as high as comparable wells in adjacent pools under solution gas drive. The adjacent pools were waterflooded in the later stages of primary depletion.

Comparison of water-oil ratio vs. recovery performance indicates that ultimate recovery for this pool will be approximately the same as that of the adjacent pools, however, the Ranger Six water-oil ratio will remain higher throughout the productive life. This will increase the cost of operation but the increase should be more than offset by the accelerated recovery. Although the report does not cover economics the present worth profit potential of Ranger Six performance cannot fail to be recognized. performance cannot fail to be recognized. The planned development of the pool for waterflooding enabled drilling fewer wells on wider spacing, resulting in a better overall flood plan than is normally possible by later conversion of a primary recovery spacing plan.

It is concluded that early waterflooding results in accelerated recovery without loss of potential secondary reserves and offers a means of increasing oil production during a time of shortage.

Introduction

The Wilmington Oil Field, as shown in Figure 1, is located on a northwest-southeast trending anticline and is cut by a system of north-south faults which divides the field into a series of fault block reservoirs.
Laboratory Studies of Biopolymer Injectivity Behavior Effectiveness of Enzyme Clarification
Authors: Burnett David B.
Published: December 2007

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

This paper was prepared for the 45th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, held in Ventura, Calif., April 2–4, 1975. 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.

Numerous studies have shown that the biopolymer XANFLOOD offers a viable alternate to polyelectrolytes such as polyacrylamides for use as mobility-control agents. Limited information is available, however, concerning the injectivity behavior of this polymer. Recent publications show that treatment of XANFLOOD solutions with certain enzymes will solubilize cellular debris and improve injectability. To study the effectiveness of this treatment, injectivity tests were Performed in a series of Berea cores Performed in a series of Berea cores with permeabilities ranging from 31 to 445 md.

The experimental results obtained from this series of tests have been correlated through the use of an "injectivity impairment" ratio, I*. When correlated to rock permeability, I* becomes a measure of injectivity behavior and shows the effectiveness of enzyme clarification.

Introduction

One of the keys to enhanced oil recovery is the use of water-soluble polymers either for use as mobility polymers either for use as mobility controls or for water-diverting agents. Of the commercially available products used in flooding, two polymers have shown the most promise: polyacrylamides and the biopolymer xanthan gum, commercially available as XANFLOOD. XANFLOOD, while being used for the same basic purpose as the acrylamides, performs in a different manner. XANFLOOD reduces the mobility of water by increasing the viscosity, not by reducing the permeability of the rock formation. permeability of the rock formation. Both laboratory studies and field tests have shown that the polymer has excellent shear stability, is insensitive to temperature, and gives high viscosity in oil field brines at low concentrations.

Rheology of XANFLOOD Solutions

Laboratory studies show that XAN-FLOOD solutions, like polyacrylamide solutions, are shear thinning. Unlike the latter, this biopolymer generally does not exhibit viscoelastic tendencies in cores.
Strategies for Steam Flood Optimization in a High-Water Saturation Reservoir in the Midway-Sunset Field
Authors: Deo Milind D. , Forster Craig , Schamel Steven
Published: December 2007

PRU Fee, an idle lease in the Midway Sunset Field has been a site of a U.S. DOE-sponsored Class III project. A geologic and stratigraphic model of the site was constructed using logs and core data. Geostatistical approach was used in generating reservoir images. Reservoir simulations were performed to study the effectiveness of various processes and to examine the sensitivity of parameters. The study showed that oil can be recovered economically from the lease using conventional steam flood technology provided the injectors are completed an optimum distance above the oil water contact. Simulations also showed that it was possible to recover additional oil by appropriately placing horizontal producers later in the life of the flood.
Investigation of Foamy Oil Phenomena in Heavy Oil Reservoirs
Authors: Albartamani N. S. , Ali S.M. Farouq , Lepski B.
Published: December 2007

The so-called "Foamy Oil" phenomenon is associated with primary cold production from heavy-oil reservoirs producing under solution-gas drive. A number of heavy oil solution gas drive reservoirs show anomalously good primary performance and high oil production rates. Example are: Lindbergh, Frog Lake, Lloydminster, and Edam in Saskatchewan. The nature of gas dispersion in oil distinguishes "foamy" oil behavior from conventional heavy oil behavior. Moreover, the important issues that distinguish foamy oil from conventional heavy oil are: the amount of dispersed gas in oil, and the time for which gas bubbles remain dispersed in the oil. These reservoirs are characterized by slower decline in reservoir pressure, lower than expected GORs, higher critical gas saturation (35% to 40%), foamy produced crude oil, and higher ultimate recovery in primary production phase. Production rates from cold production wells can be many times higher than the rate predicted by Darcy equation which does not account for sand production and the "foamy" oil behavior.

Several possible causes for the anomalous production behavior have been suggested by investigators. These include the formation of wormholes and cavities around the wellbore, sand dilation, enhancement of oil mobility by nucleation of large number of microbubbles, in-situ formation of oilcontinuous foam, influx of bottom water, and non-Newtonian flow. The work presented in this paper will review modeling foamy oil behavior by investigating the nucleation of microbubbles and the formation of in-situ oil-continuous foam. The study will focus on a critical evaluation of previous work performed by other investigators. A new experimental design coupled with an analytical approach were undertaken to unravel the problem forthmentioned.
A Wormhole Network Model of Cold Production in Heavy Oil
Authors: Yuan Jian-Yang , Babchin Alex
Published: December 2007

High permeability channels (wormholes) are believed to be generated, starting from the wellbore and propagating into the reservoir, during the initial phase of cold production. The development of wormholes drastically enhances oil production. Understanding the wormhole development pattern, therefore, is critical to the modelling of the fluid flow behaviour and recovery rates in the cold production process. We propose that the wormhole growth can be described by the probabilistic active walker (PAW) model, which is a generalisation of the classical random walk model. This simple description may lead to an improved understanding of: the mechanisms involved in cold production, the fluid flow in the area where wormholes are formed (the wormhole zone) and field production data. Previous experimental and theoretical studies indicate that the wormhole diameter may be a function of distance from the wellbore. We assume that this function follows a power law, slowly decreasing with increasing radial distance. We calculated the mobility of a slurry of sand and oil through the wormhole network. This mobility was used to calculate oil and sand production rates. Furthermore, we related the maximum size of the wormhole zone and its expansion rate to the sand production data in a typical cold production operation. This relationship can be useful in determining well spacing. This wormhole network model can also be useful as a tool for analysing field data and for the development of field scale numerical simulations of the cold production process.
Displacement Regimes in Fully-Developed Steam Injection
Authors: Yortsos Yannis C.
Published: December 2007

We present an analysis of the displacement properties during the dynamic invasion of steam in a porous medium. Two fully developed regimes are identified, similar to the Stabilized Displacement (SD) and the Capillary-Viscous Fingering (CVF) regimes of the isothermal drainage problem (Yortsos et ah, 1997). Phase change and heat transfer affect the scaling of the various properties of these regimes. Near the advancing steam front, phase change and heat transfer bring about a qualitative change in the flow permeabilities, although not in the displacement pattern, which remains of the Invasion Percolation type, if injection rates are sufficiently small. The relative permeabilities in this region are larger than those for the isothermal displacement problem. A condition is developed to delineate the regions of validity of these two regimes.
Multiphase Pumps for Minas Light Oil Steam Flood, Sumatra-Indonesia
Authors: Putra Erwinsyah , D. Uphold Donald
Published: December 2007

Multiphase pumps are modified liquid pumps that are capable of pumping various combinations of oil, water, gas, and sand in the same pipeline without separation. Minas Light Oil Steam Flood (LOSF) Pilot Project will utilize the multiphase technology to boost casing fluid with high steam and gas content from wells to the Gathering Station without prior separation. Hence, tremendous savings in capital and operating costs are realized from strategic placement of multiphase pumps since large separators, liquid pumps and compressors are eliminated.

Two uniquely different multiphase pumps, a 500 hp twin-screw pump and a 700 hp helico-axial pump, were recently tested and qualified at the Texaco Multiphase Flow Facility, where flow rates as high as 145,000 BPD and gas volume fractions (GVF) up to 100% were achieved. An illustration of each pumping unit is given followed by a presentation of measured performance data relative to the operating conditions chosen by Caltex Pacific Indonesia (CPI). Based on test results, the advantages and disadvantages of the competing technologies are compared, noting that CPI will eventually consider these data to choose either twin-screw or helico-axial technology for the Minas Light Oil Steam Flood project.

Results obtained at the Texaco Multiphase Flow Facility indicate that twin-screw pumps are 25% more efficient than helico-axial pumps. Furthermore, twin-screw pumps are virtually insensitive to liquid slugs and large changes in inlet gas density; helico-axial pumps require slug catchers upstream of the pump inlet to absorb these intermittent slugs and large variations in GVF. It is anticipated, however, that helico-axial pumps are superior in resisting long-term wear from continuous exposure of sand, which will be investigated in Duri in the fourth quarter of 1998.
The Science and Economics Behind Coiled Tubing String Design and Optimization
Authors: Portman Lance
Published: December 2007

Coiled tubing has made great advances in recent years, increasing in size, strength and reliability. This has lead to a great increase in services that can be run on coiled tubing and in turn has lead to bigger, more complex and more expensive coil equipment being built and offered to the market.

With all this new equipment now on the market, it becomes more difficult to select the most appropriate equipment for a particular job, or indeed for a project of work that involves many different types of operations. There is a tendency to assume that "biggest is best". Both commercially and technically, the big coil unit may not always be the best choice.

This paper gives examples of the current capabilities of coiled tubing units, dispelling some of the myths associated with the smaller units such as "You cannot drill with a small coil unit" or "You always need a big coil unit in order to get higher circulation rates". The paper also lists applications where big coil units absolutely should not be used. Finally, guidelines are set out based on general technical and economic performance comparisons between varying size coil units.

Several techniques are listed which permit smaller coil sizes to be used in place of bigger units. The paper uses examples from actual field work and computer simulations.
Economics of Pennsylvania Shallow Production
Authors: Jack S.W. , Stewart Robert S.
Published: December 2007

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

The scope of this paper is to outline the economic possibilities which exist in the development drilling for natural gas in Western Pennsylvania. The area studied includes five Pennsylvania. The area studied includes five counties in Western Pennsylvania and concentrates on what is generally termed the Devonian Gas Sands. The definition of shallow has been taken at an average of 3,700 feet to and through the lowest producing horizon generally completed.

This is a study of a rather typical low permeability, low porosity natural gas horizon permeability, low porosity natural gas horizon (horizons) with the associated costs on a perwell basis, and gathering costs on an average perwell basis, and gathering costs on an average basis as experienced in the field.

Ultimate recoverable reserves and expected deliverabilities are discussed with reference to the overall profit ratio to be expected on an average well of this type. The basic information required for determining the economic feasibility have been based on historical production records throughout the area from production records throughout the area from numerous sources. This approach is used as being the most reliable in an area where ultimate recoverable and deliverability projections are very difficult.

Introduction

My introduction to the gas industry came at the age of four. My father and grandfather allowed me to travel with them during a rig move in Armstrong County, Pennsylvania. At that time they moved their rig using teams. The mud was so deep that they would place me on a stump or flat rock in order not to lose me in the mud. Their largest capital item was the drilling engine, which was a one-cylinder Franklin valveless engine with a reversible clutch at a total cost of $1,200.00. Natural gas was selling for 17 cts to 19 cts per mcf; cable tool drillers were being paid $8.00 per 12-hour day. Since then, except paid $8.00 per 12-hour day. Since then, except for the time spent in grade school, Greenbrier Military School, Lewisburg, W. Va., and the time spent in Europe during World War II as a rifleman, my entire life has been spent drilling gas wells and producing gas for various gas companies in Western Pennsylvania and Northern West Virgins.

Just prior to entering the service in World War II, drilling engines were still the main capital item; Waukesha power units and Reicee drilling engines were the popular ones selling for approximately $3,500.00. Drillers were being paid $1.00 per hour, and the price of natural gas was around 20cts per mcf. Upon returning from service, the trend in the drilling business was swinging to 36L Bucyrus Erie Spudders.
The Varying Modulus of Elasticity for Coiled Tubing Material
Authors: Tipton Steven M.
Published: December 2007

Strain-controlled low-cycle fatigue testing on axial coupon samples of coiled tubing alloys have revealed that the modulus of elasticity for cyclically stabilized material is considerably lower (e.g., on the order of 20%) than the modulus measured during the initial load application or during a conventional monotonic tensile test. However, a closer analysis indicates that the majority of the modulus drop occurs during the first strain application. Additional axial testing with small elastic unload-reload excursions validate that increasing plastic deformation during an otherwise monotonic load application causes an increasing drop in the elastic modulus. In this paper, fatigue data from two coiled tubing materials are presented which demonstrate the profound influence of plastic deformation on the modulus of elasticity. The modulus decrease is explained on the basis of fundamental reordering, or texturing, within the crystal structure of individual steel grains. The lower modulus has important implications with regards to depth estimation, buckling calculation and stuck point calculation.
New Downhole Gas Separator Enhances Coiled Tubing Jetting and Stimulation Procedures
Authors: Harris J. G. , Walters W. W. , Langhoff J. A.
Published: December 2007

Coiled tubing is a live well tool that has seen tremendous growth over the last decade. A new tool designed for the use with coiled tubing removes the gas from two-phase fluids. The phase separator has been successfully used to remove drilling damage and increase production in deep, low-pressure gas wells. The phase separator can also be used to separate the gas from two-phase systems when a Positive Displacement Motor is used in drilling and/or milling applications.

The introduction of the separator is a major breakthrough in downhole jetting technology. The mechanics that effect the removal of oilfield scales and permeability damage that restrict oil and gas production as well as injectivity will be discussed. The purpose for the tool development, laboratory testing techniques and methods are also presented.

This paper will focus on the technical benefits the tool brings to jetting applications. Procedures that have not been possible in low-pressure wells may now be accomplished and will be discussed.

Highly successful case studies will be outlined and analyzed to show the benefits derived when the gas is separated from the two-phase system. Most coiled tubing applications involve jetting technology and the new gas separator will broaden coiled tubing's role in the oil and gas industry.
Utilizing 4 ½-in. Monobores and Rigless Completions to Develop Marginal Reserves
Authors: Sanford John R. , Webb Tamara R. , Patout Seb , Morales Hugo
Published: December 2007

Marginal reserves in the Gulf of Mexico (GOM) shelf can be developed using old completion technology in new ways. Tubing-less completions or monobores are one of those technologies. Several monobores have been performed in the GOM, but usually, they were not the primary completion technique. Most were performed out of necessity, either because liners were stuck above the zone of interest or drill pipe was stuck across the interval.

Large cost savings can be realized by utilizing monobores as the primary completion without impairing the completion efficiencies. By eliminating the high day rates of a conventional platform rig, a single frac packed completion can be performed for less than $ 500,000.

This paper describes a technical review of two 4-½″ monobore completions that were performed in Eugene Island (EI) 273 to recover marginal reserves. The monobore completions were planned as the primary completion technique. However, several changes were made to the monobore completion as compared to conventional frac packing technology. For example, we utilized oriented, limited entry perforating (0°/180° phased and 0.25″ diameter entry holes, 4 shots per foot (spf) and no annular pack.

Many key learnings were identified during the completions and several changes were made prior to the second completion. These changes resulted in an overwhelming success both mechanically and financially. The second well, EI 273 Well C-1ST, was performed in less than 5 days at a cost of $ 465,000. The completion efficiency is 88 % and maximum sustained production was 20,000 mcfd.
Problems Of Independent Producers Subject To Federal Regulations
Authors: Gehr James G.
Published: December 2007

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

It is a daily occurrence to read and hear about our energy crisis. It is, and should be, everyones concern. The small voice of the independent oil and natural gas producer has been heard but not heeded. The independent oil and Gas Association of West Virginia, recognizing these problems, set out to correct the situation. It seemed that a reasonable solution should be attainable. However, we have experienced many setbacks which have been both expensive and frustrating. We have gained a great deal of respect for the problems of the interstate pipeline companies and the impossible task of federal regulation of natural gas prices.

The constant turmoil created by the Natural Gas Act and indecisions of the Federal Power Commission and Congress has put the entire petroleum industry, and put the entire petroleum industry, and especially the small independent, close to the point of extinction.

This cloud over our heads is certainly discouraging; however; we must not decrease our efforts toward a just and free enterprise system.

Background

The basis of our problem stems from the Natural Gas Act of 1938 passed by Congress. The Act required the Federal Power Commission to regulate the price of natural gas sold in interstate pipeline systems. The trouble started in 1954 when the FPC was ordered by the Supreme Court to also set prices for producers. This task of determining "just producers. This task of determining "just and reasonable" prices individually for thousands of producers, turned into a real monster. So by 1960, the Commission publicly announced that even if its Staff were tripled, it couldn't catch up with pending cases for 83 years.

Several attempts have been made by the FP C to accomplish fair regulation. Geographical areas were set up where supposedly costs of operating were equal.
High-Pressure Coiled-Tubing-String Design
Authors: Zheng Andrew S. , Larsen Henrik A.
Published: December 2007

High-pressure coiled tubing applications pose many technical challenges to coiled tubing string design: collapse, diametral growth, elongation and wall thinning, to name a few. This paper discusses an optimal string design methodology for coiled tubing in high pressure applications. The string design methodology uses a sophisticated collapse-prediction model for oval coiled tubing, taking into account the effect of axial load on collapse resistance. It also considers the effect of diametral growth, elongation and wall thinning on the performance of a high-pressure coiled tubing (HPCT) string. By integrating these design parameters into the framework of an optimal string design methodology, this paper presents an effective approach for high pressure coiled tubing string design. The paper also presents examples of HPCT string design. It is demonstrated that it is possible to design HPCT strings capable of withstanding more than 9000-psi collapse pressure while maintaining the field usability of the HPCT string.
Results of Recent Inspections Performed on Coiled Tubing
Authors: Stanley Roderic K.
Published: December 2007

The full-length NDE inspection of coiled tubing is now well established, and it is expected that NDE will play an increasing role in setting quality standards for used coiled tubing. Nondestructive Evaluation (NDE) methods are currently being documented into the API Recommended Practice for Care, Maintenance and Inspection of Coiled Tubing in order to set baseline requirements for inspection, and should form an integral part of a string management programme. Non-contact electromagnetic techniques for wall thickness measurement, ovality measurement, and flaw detection are in use in such tools, and have resulted in the following: detection of internal corrosion, section removal from the bed-wrap, downhole, and mid sections of tubes, scrapping entire tubes, and the detection of heavily fatigued areas in high strength tubing.

This paper indicates the type and value of the information that has been collected by performing NDE inspection, and presents the results of some recent inspections in detail. The paper also indicates the need for universal rules for derating sections of tubing in terms of both wall condition and consumed fatigue life.

The development of a universal vocabulary for the problems associated with coiled tubing in use that is consistent with current API terminology is also discussed.
Deepwater Mooring System Using CT Technology
Authors: Head Phil , Turner Dan , French David , Hanson Tim , Cameron Gerry
Published: December 2007

This paper provides an introduction to a joint industry project (JIP) which plans to employ coiled tubing (CT) from the deck of a vessel to deploy and install anchor points for mobile offshore drilling units requiring deepwater moorings.

CT offers significant advantages for installation of anchor points. It is a rapid conveyance means to the seabed; in addition it can supply significant power for drilling and is a circulation means once there. It provides the means for deploying anchors to considerable depths in the seabed, as appropriate to provide the necessary retainment force.

The vessel can then immediately perform a proof load test on the mooring line to ensure the quality of the anchor point. Only if it meets the required capacity is the CT then disconnected and recovered back to the vessel to collect the next anchor assembly and mooring line. To unset the anchor point, the mooring line is pulled taut and a release tool is dropped down the mooring line, close to the seabed, to activate a release mechanism which allows the mooring line to come free.

The concept offers many advantages over conventional anchors, including:

Pin point accuracy with reference to the mooring pattern centre.

Rapid and accurate anchorage deployment to significant depths into the seafloor

Very high ratio of pull-out force to weight of anchor equipment

Reduced difficulties in transportation and handling and therefore increased safety for anchor handling personnel.

Significantly reduced CAPEX and OPEX.

Simple recovery of anchor and mooring line when released from rig.
Dynamically Overbalanced Coiled Tubing Drilling on the North Slope of Alaska
Authors: Kara D. T. , Gantt L. L. , Blount C. G. , Hearn D. D.
Published: December 2007

Coiled Tubing Drilling (CTD) continues to play a dominant role in through-tubing sidetracking of wells on the North Slope of Alaska. Recently several CTD candidates were targeted in an over-pressured reservoir. Three wells were successfully CT sidetracked as a pilot project in this over-pressured reservoir. The ultra-slimhole directional drilling system −2.75″ nominal openhole diameter-developed at Prudhoe Bay1 was used in combination with an unconventional approach to maintain overbalanced conditions when sidetracking these wells.

Hydraulic modeling showed that with a kill weight drilling fluid, the calculated Equivalent Circulating Density (ECD) at the sand face could approach the regional fracture gradient. In addition, kill weight mud in the formulation required for CTD operations would be a significant expense. To address these concerns, the wells were CT sidetracked using a less expensive under-balanced drilling fluid system. Although the drilling fluid hydrostatic pressure was less than reservoir pressure, over-balanced drilling conditions were dynamically maintained by the high ECD while circulating, and controlled by increasing the surface pressure using a choke when circulating at less than drilling rates.
High Pressure Coiled Tubing Instrumental in Deep Water Well Work
Authors: Larsen Henrik Aslak , Porter David A. , Peterson Chad
Published: December 2007

High Pressure Coiled Tubing (HPCT) has been utilized to perform stimulation, memory production logging, plug retrieval, washing across a gravel pack screen and gravel pack logging. The two jobs reported here comprised of seven runs.

The work was performed in the Gulf of Mexico on the Troika field in Green Canyon 200 (Figure 1). The rig was Global Marine's semi-submersible the Glomar Arctic 1 working in approximately 2700 feet of water.

The wells are high rate, high-pressure oil wells. They are capable of flowing in excess of 30,000 BOPD and 60 MMSCFD. This field has reset the Gulf of Mexico record for the highest rate oil producers.

Operations were performed with up to 9 feet of heavy seas with 6,600 psi on the well head and at 18,300 feet total depth.

The objectives of both jobs were met, and the extreme well conditions pushed the operating envelope of the equipment and the personnel. The authors believe that the quality of onsite personnel, a steep learning curve along with generally accepted best practices, and advances in procedures and equipment allowed the successful execution of these jobs.

The cost of the CT was approximately 10% of the total daily operational cost.
Simulation of the Bradshaw Berea Field
Authors: Royo Carlos M.
Published: December 2007

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

A numerical model was used to simulate a portion of the Bradshaw Gas Reservoir and to portion of the Bradshaw Gas Reservoir and to evaluate the effect of well spacing and gathering-system pressure on production. A model study of the entire reservoir was not warranted because of limited data. After selecting a portion of the reservoir for which production data were available, an acceptable production data were available, an acceptable history match was obtained and performance prediction runs made to simulate the reservoir prediction runs made to simulate the reservoir under different future operating conditions.

Following the reservoir study the effect of well spacing on economics was determined. Production forecasts were obtained for well Production forecasts were obtained for well spacings ranging from 150 to 400-acres and for formation thicknesses of 20 and 25 feet. For each case, the economics of a typical well were determined for four gas price levels, including the current price. The results show that while the profitability index increases as well spacing increases, the present worth value calculate at a ten percent discount rate exhibits a maximum within the range of well spacings investigated. The maximum value depends on the gas price and the formation thickness.

Introduction

The Bradshaw Gas Field is located in McDowell County, West Virginia. The reservoir is a tight, relatively low-pressure Berea sand at an average depth of approximately 4000 feet, with first production established in the middle 1960's. Development of the reservoir was based on 150-acre to 300-acre spacing depending on the operator. Cities Service Oil has been producing its wells since 1966 on 300-acre spacing. producing its wells since 1966 on 300-acre spacing. This investigation was initiated to answer several questions concerning the development of the reservoir. Of particular interest was the optimum well spacing because portions of the reservoir still remained to be developed. Also, infill drilling could be initiated at several locations provided 150-acre or 200-acre spacing proved to be more economically attractive than proved to be more economically attractive than 300-acre spacing. Another objective of the investigation was to determine the effect of lowering the gathering-system pressure on production. At the time the study was production. At the time the study was undertaken, Cities Service Oil was delivering gas at a line pressure of 250–300 psig, while outside operators were producing into a line pressure of about 150 psig. In addition, other pressure of about 150 psig. In addition, other operators had drilled several wells and planned to drill several more on small leases along a railroad right-of-way which goes through some of Cities Service Oil leases.
Use of Resin-Coated Proppant to Control Shallow, Low-Temperature Unconsolidated Sands
Authors: Geehan T. , Deckert S. L. , Johnson K. , Arnold W. T.
Published: December 2007

The paper describes two applications of different resin-coated proppants to obtain a consolidated proppant pack to reduce proppant flowback and formation sand production.

The zones of interest are part of the Schrader Bluff development project. Three zones were treated; one was in the deeper, more consolidated O sand formation, and two were in the less consolidated N sand. The problem of sand production was further complicated by the viscous nature of the oil in place, which was in the range of 17 to 21 API.

The reservoir temperatures ranged from 80° to 110° F. In the higher temperature zones, the catalyst required to initiate the resin set was more benign and thus allowed the use of a cross-linked borate as the base fracturing fluid. In the cooler formation, the complexity of the operation was increased by the need for a catalyst based on a mixture of acid and alcohol. This was required to ensure the resin-coated proppant pack obtained sufficient compressive strength to withstand the viscous drag of the heavy oil. The need for the more aggressive catalyst in the lower temperature zones necessitated the use of HEC as the base fluid for fracturing because the catalyst was incompatible with borate-based fluids. The composition of the catalyst was modified to meet the safety standards for pumping as demanded by the operating procedures from the service company.

The paper also describes the fracture geometry determined from analysis of the treating data and the production results from the treated zones.
High GOR Wells Optimization, Prudhoe Bay Practice
Authors: Peruzzi Tave , Krumanocker Erich
Published: December 2007

Many oil fields are gas handling limited. A requirement or desire not to flare and the relatively higher costs of gas compression compared to liquid handling are the main reasons. Optimization of high GOR wells in gas handling limited fields should result in a higher field oil rate. This paper describes high GOR well optimization in Prudhoe Bay. This description may provide ideas applicable to other gas handling limited fields.

In this paper the problem of high gas/oil ratio well optimization is explained. Empirical observations, strategy, tools and examples for optimizing high GOR wells in a gas constrained field are presented. Overall results, as well as specific well production responses, are discussed.
An Improved Sandstone Acidizing Model: The Importance of Secondary and Tertiary Reactions
Authors: Murtaza Ziauddin , Berndt Oliver , Robert Joel
Published: December 2007

An improved model for sandstone acidizing is presented, following a review of sandstone acidizing models. The improved model resolves complex sandstone mineralogy into eight distinct minerals instead of two or three minerals as was done previously and uses empirical correlations to compute equilibration between various aluminum and silicon fluoride species. The improved model provides a reasonable estimate of porosity evolution and acid consumption for most sandstones with known mineralogy, and unlike previous models it does not require experimental predetermination of acid capacity and Damköhler numbers. Validation of the model with several sandstones for a wide variety of injection rates and temperatures is presented. Sensitivity analyses performed with the model are also discussed.
Towards Proppant Back-Production Prediction
Authors: van Batenburg Diederik , Biezen Ewout , Weaver Jim
Published: December 2007

Proppant back-production from hydraulically fractured wells is a great operational problem to the oil and gas industry. Apart from safety problems related to erosion of tubing and valves, extra equipment and operators are required to handle wells that produce proppant. Substantial work has been conducted to develop methods to control proppant back-production. The methods include the modification of completion designs, the use of controlled fracture closure to obtain early closure on the proppant and the use of new materials designed to prevent proppant production. These materials include curable resin coated proppant, fiberglass, thermoplastic filmstrips, and chemicals that modify the surface of the proppant. Relatively little effort, however, has been directed towards understanding the mechanisms that cause proppant back production. A review of the relevant literature shows some experimental studies at a laboratory scale and one numerical study on the mechanical stability of proppant packs.

This paper presents the results of combined experimental and modelling studies to quantify parameters critical to proppant back-production. Laboratory experiments were conducted in several slot flow models. The experimental results were used to calibrate a numerical model to predict back-production. In the model flow inside the proppant pack is described by Darcy's equation for flow through porous media. The resulting velocity distribution is used to assess the local stability along the free surface between the proppant pack and the continuous fluid phase. These steps are repeated to evaluate the development of the interface over time. Similar methods have been used to describe viscous fingering in petroleum reservoir engineering. However, in viscous fingering the interface moves in the same direction as the fluid while the directions are opposite in the application described here.

Example simulations show how stable open channels can develop in propped hydraulic fractures. The results provide a foundation for the existence of such channels as has been speculated and hypothesized by many people over the last couple of years.
Simulation of Fractures Induced by Produced Water Re-Injection in a Multi-Layer Reservoir
Authors: Gheissary G. , Fokker P. A. , Egberts P. J. P. , Floris F. J. T. , Sommerauer G. , Kenter C. J.
Published: December 2007

In a recent study a numerical model for Produced Water Re-injection (PWRI) under fracturing conditions was presented [1]. The model was a 2-dimensional analytical fracture growth model and hence only appropriate for constant-height fractures fully penetrating the injection layer, with a "square fracture" option allowing a first order estimate of radial fracture dimensions. In this paper we present a new 3-dimensional fracture growth model which permits the description of elliptical fractures in a multi-layer reservoir with fracture length, height up and height down all potentially growing at different rates.

The pressure field in the formation around a fully contained elliptical fracture will resemble that of a fracture in an unbounded reservoir (i.e. 3D solution), while far into the reservoir it will approach a 2D solution, with a gradual transition between the two limiting cases. Solutions to both of these limiting cases have been developed earlier [2,3]. Here we present a new method which approximates the gradual transition from 3D-elliptical symmetry to 2D-elliptical symmetry with an abrupt transition. In a multi-layer reservoir the model can be applied independently to all the layers if no crossflow between the layers is allowed.

A comparison is presented between the two models which demonstrates that the previous model predicts larger fracture sizes. This is particularly the case if the pressure drop over the filtercake is relatively small.

We also present a new approach to represent plugging within the fracture due to the build-up of filtercake resulting from suspended particulates in the produced water. This new approach allows for flow channels to develop within the filtercake in the fracture, rather than the approach used in the previous study which adopts a parallel-plate flow model and allows uniform growth of filter cake on fracture walls.

A number of PWRI field examples is also presented. The model is very suitable to assess the containment capacity of layered reservoirs, which is demonstrated using a field example of a large reservoir in the Middle East.

Comparisons with Prudhoe Bay data show that our model is not capable of predicting the virtually immediate response to changes in the water quality. The model still assumes that the filtercake properties are determined by the cumulative volume of solids pumped into the fo rmation. This needs to be reviewed and possibly extended to also include immediate effects.
Acidizing Deep Open-Hole Horizontal Wells: A case History on Selective Stimulation and Coil Tubing Deployed Jetting System
Authors: Mascarà S. , D'Ambrosio A. , Zambelli A. , Gili V. , Loving S. , Dossena M.
Published: December 2007

The Val D'Agri field is located 20 Km SE of Potenza (Basilicata) in Southern Italy. The aerial extension of the field covers approx. 250 Km2 mostly (2/3) in the mountainous region (more than 1000 m. a.s.l.) of the field, while the remaining part is located in the river Agri valley at 600 m. a.s.l.

The field is divided into five blocks: Grumento Nova, Corleto Perticara, Caldarosa, Volturino and Tempa Rossa, operated by ENI Agip Division on behalf of different Joint Ventures, comprised by Enterprise Oil, FINA, and Mobil.

From 1980 to present 24 wells have been drilled by ENI Agip Division. The most significant discoveries have been Costa Molina 1(1980) and Monte Alpi 1 (1988), in the southern part, Cerro Falcone 1 (1992), in the northern part, and Monte Enoc 1 (1994), in the central part of the field which confirmed a unique reservoir. Val D'Agri is currently the most interesting Italian region for hydrocarbon production, and probably the most demanding from the completion technology point of view.

The overall plan is to drill more than 50 wells and produce about 100,000 bopd when the oil treating center and the pipeline network will be completed.