bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydrocarbon Location by Cased-Hole Methods in Mid-Continent Wells
Authors: Ermey B.R. , Alger R.P.
Published: December 2007

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

This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 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 presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is 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. 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.

When production from a well falls below the profitable level, usually due to declining profitable level, usually due to declining reservoir pressure, the producer must decide whether to abandon, recomplete, or begin secondary-recovery operations. Until recently, the choice was made very difficult by the scarcity of reservoir-rock information obtainable from the existing logs.

The development of new took and techniques for logging in cased holes has greatly improved this situation. A modern logging program for these old wells might consist of a Dual-Spacing Neutron Decay Time tog, a Compensated Neutron log, and, where applicable, a cased hole Formation Density log. These, in conjunction with the original open-hole logs (usually a vintage Electrical Survey or a Gamma Ray-Neutron log) permit much better accuracy and reliability in the determination of porosity, fluid saturation and in some cases the type of hydrocarbon behind the pipe.

This paper presents several examples of Mid-Continent wells which were logged by such modern techniques. In each, the cased-hole logs allowed the producer to select with confidence the most appropriate action for his well.

Introduction

Developments in technique and equipment have brought a new order of reliability to log evaluation in cased holes. The key to these advances is the Dual-Spacing Thermal Decay Time device (TDT*-K). Also useful are the Compensated Neutron and Formation Density logs, which can be run in combination, and which under favorable conditions will provide good porosity determination and gas detection in cased holes.
Recipe for Heating and Recovering an 800 Foot Column of Heavy Oil, Potter Sands, Midway-Sunset Field, California
Authors: Lolley C. S. , Fram J. H. , Fortier J. D. , Deemer A. R. , Robinson K. L.
Published: December 2007

This is the first in a series of papers detailing the development of an 800-foot thick Potter sand oil column on the northwestern boundary of the Midway-Sunset oilfield in west-central section 21N, T31S, R22E. Tools used to develop the depletion strategy for this property include analogy and thermal numerical simulation. This viscous 11° API crude is currently producing 1500 bopd under cyclic steam support. This area will be re-developed as a steam flood over the entire 81 acres. Besides the viscous nature of the crude and the massive volume of reservoir that must be heated, another technical challenge is the presence of low pressure vadose or air sands immediately above the oil column. These air sands will act as a thief zone to the injected steam and will make heating this massive oil column more difficult. These challenges posed the following question: How does one effectively heat an 800-foot thick oil column without having the steam preferentially rise to the top of the column and into the low pressure air sands?

To adequately develop guidelines for steam injection rates and placement, a numerical simulation model with sufficient gridblock and compositional resolution was used to accurately simulate the countercurrent flow of steam and oil as the steam rises to the top of the reservoir. A two dimensional mechanistic model with very fine gridblocks was used to isolate this mechanism. Gridblock dimensions were calculated using a characteristic length, and the steam assisted gravity drainage (SAGD) process was used to estimate the rate of rise of the vertical steam chest. The oil was characterized by a 5-component system that was fully compositional and could simulate the complex phase behavior associated with the oil and steam rising into the air sands. The techniques used in the study resulted in a numerical model with sufficient resolution to provide guidelines for steam injection rates and for steam placement within the 800-foot thick oil column.

This project is under active development with over 130 wells drilled and completed in 1998. Future papers will detail the producer/injection well completion strategies and the steps used to optimize the recovery process.
CO2 and Miscible Gas Injection for Enhanced Recovery of Schrader Bluff Heavy Oil
Authors: Khataniar S. , Kamath V. A. , Patil S. L. , Chandra S. , Inaganti M. S.
Published: December 2007

The Schrader Bluff Pool in the Milne Point Unit, Alaska, is estimated to contain 1.5 billion bbl of heavy oil. Due to the lack of any significant primary recovery mechanism, enhanced oil recovery methods are considered for early stage application. Availability of hydrocarbon gases and CO2 on the Alaskan North Slope makes a miscible solvent injection process attractive. Therefore, the objective of this study was to experimentally investigate the performance of CO2 injection and miscible WAG processes for enhanced recovery of Schrader Bluff heavy oil. From slim tube experiments, CO2 was found to be immiscible with Schrader Bluff oil at reservoir conditions. Prudhoe Bay gas (PBG) enriched with at least 50% natural gas liquids (NGL) achieved dynamic miscibility with the crude oil. Coreflood experiments in 4 ft long sandpacks were conducted using CO2, and a mixture of 50% PBG and 50% NGL as the solvents to study the effects of slug size and WAG ratio on displacement of Schrader Bluff oil at reservoir conditions. These experiments showed that there was no significant improvement in the incremental oil recovery (IOR) for PBG/NGL slug sizes larger than an optimum value, however, the highest IOR per unit slug size occurred for a much smaller slug size. On the other hand, a single, small CO2 slug resulted in almost same IOR as a large PBG/NGL slug. Thus, CO2 had the highest IOR per unit slug size although it was immiscible with the oil. The IOR from PBG/NGL multiple slug WAG decreased asymptotically with increasing WAG ratio and a single slug WAG resulted in highest IOR per unit slug size. Thus, in coreflood experiments, a small single slug of 50% PBG and 50% NGL mixture, or of CO2 appears to be most efficient in improving oil recovery.
The Development of Heavy Oil Fields in the United Kingdom Continental Shelf: Past, Present and Future
Authors: Jayasekera A. J. , Goodyear S. G.
Published: December 2007

Historically, most UKCS production has been of light oil, 30° API and above. However, since 1993, a number of heavy oil fields have been brought on production. This paper reviews the history of UKCS heavy oil, the challenges overcome to bring these fields to development, and the future outlook.

The occurrence and distribution of the UKCS heavy oil in place is discussed. A specific correlation to estimate reservoir viscosity from API gravity is presented. Productivity of heavy oil reservoirs is compared with light oil developments, different categories of heavy oil reservoirs are identified, and the use of horizontal or multilateral well technology to achieve acceptable production rates is discussed. The implication of well productivity testing (e.g. extended well testing) of appraisal wells is discussed.

The development challenges that have been overcome in current developments (Harding, Gryphon, Alba, Captain) are reviewed, in particular focusing on well productivity, pressure support, recovery efficiency (management of gas and water coning, areal sweep), and oil water separation. The paper will also review the cost and risk management strategies that need to be adopted to enable the economic exploitation of these heavy oil resources in a demanding environment such as the UKCS.

Finally, the potential for future heavy oil developments is discussed. The scope for IOR technology to increase reserves in heavy oil fields on production by waterflood, or to improve the economics of currently sub-economic fields, is reviewed, focusing on advanced well technology, downhole separation, thermal techniques and conformance control methods.
An Analytical Model for Light Oil Recovery by Steam Distillation
Authors: Mamora D. D. , Sutadiwiria G.
Published: December 2007

Distillation of oil at the steam-oil interface has long been recognized as an important mechanism for oil recovery during steam flooding, particularly in light-oil reservoirs. However, the heat and mass transfer mechanisms at the interface are not well understood.

This paper describes an experimental study conducted to shed more light on these mechanisms. The apparatus used consisted of a vertical sand pack containing a three-component liquid mixture, namely, cyclohexane, n-octane, and water. Cyclohexane has a boiling point lower than that of the steam introduced at the top of the sand pack, so that this hydrocarbon component will be predominantly distilled off. Data obtained included produced hydrocarbon and water volumes, sand-pack temperature profiles, and steam front velocity as measured with the aid of the CT scanner.

Analysis of the data indicates that, contrary to the usual assumption, steam distillation does not occur at equilibrium conditions. Moreover, oil recovery by steam distillation is largely dependent on the steam saturation point and injection rate. Based on these findings, an analytical steam displacement model has been developed. Temperature profile, steam front velocity, and hydrocarbon production based on the model agree satisfactorily with the experimental results.
Low Surface Tension Hydrochloric - Hydrofluoric Acid Mixtures in Low Porosity, Low Permeability Sandstones
Authors: Holcomb David L.
Published: December 2007

Hydrochloric - Hydrofluoric acid mixtures have long been topics of investigation with respect to the optimum requirements of concentrations necessary for effectiveness in the stimulation of low Porosity, low permeability sandstone reservoirs. Low permeability sandstone reservoirs. Low concentrations of hydrochloric and hydrofluoric acid in combination with one another (i.e., 3 per cent HCl - 0.6 per cent HF) provide a highly efficient system whereby less damaging reactions occur in the sandstone matrix or fracture system, thus reducing the damage caused by migrating and sloughing fines produced when conventional HCl-HF systems (i.e., produced when conventional HCl-HF systems (i.e., 12 per cent HCl - 3 per cent HF) are used. In addition, the ability of the low concentration HCl-HF system to overcome the capillary imbibition effects, which tend to reduce the efficiency of load fluid recovery following stimulation of a low porosity, low permeability sandstone reservoir, is permeability sandstone reservoir, is enhanced by using ultra low surface tension reduction via the application of a low adsorption, cationic, fluorocarbon surfactant. Coreflow studies illustrate the above nontioned principles.

Introduction

A significant mechanism for stimulation of low permeability, low porosity, well consolidated sandstone reservoirs is the efficiency and effectiveness of utilizing low concentrations of both HCl and HF acid coupled with fluorosurfactants which can be gel ed with low residue polymers for fracture - acidization with proppant incorporation.

Two-thirds of the world's oil is found in sandstone formations. Problems with regard to treatment technique and type range from saturation and clay swelling to regarding clay particle migration, fluid-formation compatibility, shale sloughing, and fluid recovery.

Reactions and reaction products have been extensively researched, and it is not within the scope of this paper to dwell upon or challenge them.
Perforating at Base of or Below Sand and Fracturing Improves Well Performance
Authors: Holm Anchor E.
Published: December 2007

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

This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 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 presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is 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. 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.

During 1972, severe Dakota formation fracturing treatments were evaluated using temperature surveys, primarily. Created fractures were found to propagate upward into non-pay. Thus, below the pay perforations were attempted, and successful treatment the well resulted with better productivity A Workover had similar results.

Introduction

During 1972, El Paso Natural Gas Company completed eighteen gas drilled Dakota wells, running fracture evaluation logs. Five wells had perforations placed in the bottom or below the pay zones. This was done to evaluate the upward propagation of the induced fractures and improve the fracturing treatment.

The San Juan Basin (Fig. 1) is located in the northwest portion of New Mexico on the Eastern edge of the Colorado Plateau. Most production In the Basin has a Northwestern production In the Basin has a Northwestern trend. The Dakota formation is a tight (0.01 md) gas producing sand-shale sequence, deposited primarily as a moving shoreline trending primarily as a moving shoreline trending Northwest - Southeast with some deltaic deposition in local areas. Fig. 2 is a typical Gamma Ray/Induction Resistivity log of the Graneros - Dakota zone averaging about 250 ft. thick at a depth of 6000 to 8000 ft.

Drilled on a 320 acre spacing, each well had 4 1/2 in. casing set thru the Dakota formation in a 6 1/4 in. gas drilled hole or 7 7/8 in. mud drilled hole. Each pay zone was perforated with 16 to 20 shots per zone and the perforated with 16 to 20 shots per zone and the well hydraulically fractured with 40,000 to 90,000 lbs. of 20/40 sand at about 1 lb./gal. of fresh water treated with 3% calcium chloride and 2 lbs. of friction reducer per 1000 gal. Rubber covered nylon balls were dropped during the treatment in order to treat all zones.

All of the sixteen evaluated wells shown on Fig. 3 were gas drilled.
Effect of Temperature on Heavy Oil/Water Relative Permeabilities
Authors: Akin Serhat , Castanier Louis M. , Brigham William E.
Published: December 2007

In the first part of this study, the accuracy of the JBN technique for the determination of heavy oil/water relative permeabilities, and the effect of temperature on relative permeabilities is examined by giving numerical as well as experimental examples. Using the JBN technique leads to a false temperature dependence of relative permeability curves. In the second part, we present unsteady state relative permeability experiments with initial brine saturation at differing temperatures conducted using South Belridge sand and heavy oil. A new three step experimental technique and an analysis procedure were developed to test the effect of temperature on relative permeabilities. In this technique, an ambient temperature unsteady-state relative permeability run is conducted in the first stage, and following that the temperature is increased twice (i.e. 122°F and 150°F). Two phase saturation profiles along the sand pack are measured using a CT scanner. A commercial black oil simulator, coupled with a global optimization code is then used to estimate two phase relative permeabilities. Experimental saturation profiles, differential pressure and recovery data collected from both the ambient and higher temperature data are used in the numerical model. It has been observed that a single set of relative permeability curves can represent both the ambient and high temperature parts of the experiment. This suggests that relative permeability is not a function of temperature at least for the system tested.
Pipe and Supplies Shortages
Authors: Moore Wendell S.
Published: December 2007

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

Introduction

The Arab embargo of oil shipments to the United States in 1973 as a result of the United States' support of Israel in the Arab-Israeli Yom Kippur war, and the subsequent formation of OPEC (Organization of Petroleum Exporting Countries), who instituted a worldwide increase in oil prices, triggered a reaction in the Unite States that is still far from settled.

The year 1974 was confusing at best—high interest rates, tight money supply, materials shortages and all-out production, rapidly accelerating inflation after price controls, and lifting of the oil embargo—all occurring more or less simultaneously. Then some cooling of economic growth became apparent; real GNP declined for four successive quarters.

Consumers, who lost buying power to inflated prices, decreased their purchases. Appliances, textiles, furniture, and housing construction moved into a deep recession. U.S. automotive production for the model year was off 30 percent, and sales curves show no real recovery yet in 1975 despite high-powered promotional campaigns. promotional campaigns. In the early months of 1974, the capital goods market seemed immune to growing recessionary signs. There existed a pent-up demand for increased plant capacity in many sectors after price controls expired. Environmental price controls expired. Environmental considerations had forced the shutdown of many facilities that could not operate profitably, and unprecedented activity began to increase electrical generating capacity and fossil fuels supply. Accelerating escalation rates and lengthening materials lead times continued into September.

Then signs of some decline in the rate of those increases began to appear. Nevertheless, in continuing short supply were: steel, forgings, castings, ferroalloys, pig iron, motors, coal, coke, bearings, fasteners, pipe, and pipe fittings. All of these items were needed for energy projects.

HISTORY

To counteract the implications of U.S. dependence on imported oil, The Federal Energy Administration in its "Project Independence Blueprint" started an all-out domestic energy search.

In the U.S., rising oil and gas prices touched off the biggest oilfield rush since the 1950's. It became apparent quickly that the industry was geared to drill more wells than there were pumps, piping, and associated equipment available to bring products to the surface.
Through-Tubing Inflatables: Isolation and Guidelines for Coiled-Tubing Applications
Authors: Mackenzie Gordon R. J. , Plante Mark E.
Published: December 2007

When planning a well intervention, there are many factors that need to be taken into consideration prior to the execution of the operation. The operator has many tasks to perform before the actual job and the last thing he or she wants to worry about is "Have I chosen the right isolation device and has this equipment been custom-fitted for my application?". Last, "does the performing service company have the ability to engineer the job correctly?" This paper will attempt to cover set up for thru-tubing inflatable devices run on coiled tubing.

This paper will examine guidelines with regards to the planning and execution of well interventions using thru-tubing inflatable devices such as bridge plugs (both permanent and temporary), packers, cement retainers and straddle systems. Discussion will involve the information required to be collated prior to equipment selection and job engineering and how said information relates to the equipment's performance and overall success or failure of the objectives of the intervention. Also discussed will be the most common failure methods of such devices and information with regards to preventative methods and practices to minimize such failures, taking into consideration information gathering, technological developments and correct tool usage. The paper will go on to highlight the impact of hydraulic considerations with regards to applied pressure differentials and drawdown or inflow testing, as it effects inflatable isolations, before, during and after the installation.
Scale Removal From the Recesses of Side-Pocket Mandrels
Authors: Tailby R. J. , Amor C. Ben , Mc Donough A.
Published: December 2007

Hard scales like barium and strontium sulfate have proven to be extremely difficult to remove from well completion by existing mechanical or chemical means.

A North Sea operator recently experienced scale deposits, which were identified to be barium sulfates, in the side-pocket mandrels of a gas-lift completion. Valves could not be retrieved and so a failure would have resulted in a workover. Solvent soaking together with agitation with a wireline brush, which had been successful in the accessible area of the TRSV, was ineffective in removing enough scale to allow kickover tools to function.

A new through tubing technique to selectively remove hard and inert scales has been in development for several years. The method is based on abrasive jetting technology using a new coiled tubing tool and consists of pumping specially manufactured particles through a rotating nozzle. These particles are softer than the tubular material yet hard enough to break the scale.

This paper describes the first use of the technology in the North Sea. Used in conjunction with coiled tubing, the technique was successful in removing enough of the scale for the kickover tool to engage, latch and pull the valve. Photos of the cleaned valve, post job Gamma Ray logs and solids analyses show clearly that the majority of the scale had been removed.
Development of Welding Procedure Specification for Girth Welds in Coiled Tubing
Authors: Luft H. B.
Published: December 2007

As oil and gas well servicing operations involve increasingly larger coiled tubing (CT) sizes, the ability for extending their useful or working life becomes of increasingly greater economic importance. Not only do larger tubing sizes exhibit inherently lower fatigue lives, but also their replacement cost is considerably greater. Efforts are underway elsewhere for developing CT repair strategies for recovering some of the CT fatigue life that has been reduced due to dents and other damage or degradation of the tubing. Such local repair methods, however, have both material and practical limitations. The capability to remove finite section(s) of tubing that has been damaged or expended a greater percentage of its working life, would be of significant benefit rather than force the retirement of the complete tubing string. Removing sections of excessive ovality and subsequent replacement with new sections without discarding the complete tubing or the ability to extend the CT string length, are further examples of the benefits of performing reliable on-site girth-welded connection(s) in coiled tubing.

This paper describes the weld procedure specification (WPS) under development at BJ Services. The procedure utilizes an orbital tungsten inert gas (TIG) welding process equipped with a full-function "Magnatech D-Head". The welding sequence consists of a fine stringer bead technique for maximum grain refinement and a strategic control of heat input, preheat and interpass temperature control. Mechanized systems for tubing ovality removal, reaming of internal ERW seam weld flash and girth-weld edge preparation, are utilized to their fullest extent to maximize repeatability of the weldment integrity and minimize reliance on welder skill and quality of workmanship. Preliminary test results obtained indicate that the low-cycle plastic fatigue life of these mechanized girth welds can be increased by at least 100% compared with what is generally attainable from manual TIG girth welds in coiled tubing.
Industry Guidelines for Underbalanced Coiled Tubing Drilling of Critical Sour Wells
Authors: Luft H. B. , Wilde G.
Published: December 2007

Oil and gas well drilling using coiled tubing (CT), in general, is continually increasing. Because a significant portion of this drilling activity could involve critical sour environments, the industry and regulatory bodies have recognized a lack of adequate guidelines for under-balanced drilling of wells containing hydrogen sulfide. Drilling using coiled tubing (DUCT) in critical sour wells is currently not permitted pending the development of such guidelines. A key element of safe and reliable drilling operations in sour wells, is the materials integrity of coiled tubing when subjected to a wet hydrogen sulfide environment.

Considerable laboratory testing and investigation of small-scale, standard NACE test specimens, has already been performed, primarily through a prior joint industry project6 (JIP). These tests did not show unequivocally that coiled tubing steels could be used in sour environments without protection by corrosion inhibitors. Considerably more laboratory testing is indicated. A combined industry effort is required that will compile all laboratory test results from which must evolve a meaningful and practical set of operational guidelines for use with actual full sized drill strings and associated equipment. This paper presents the background to these developments, a review of the materials problem, discusses results from new a new testing method and additional laboratory specimen testing that is required to address any deficiencies or lack in essential data.

Analogous to the development of CT fatigue life predictions, full-scale "corrosion fatigue" testing under representative loading and sour environments, is proposed. A methodology is required to integrate the materials response from these test results into the actual systems response of a CT drilling string operating in sour wells.

For readers unfamiliar with the technical issues of corrosion fatigue we included extensive appendices giving information related to CT chemistry, metallury and service conditions in sour environments.
A "New" Gas Supply - The Devonian Shales
Authors: Foster John M.
Published: December 2007

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

For the past 2-1/2 years, Columbia Gas System, through its Research Department and operating Companies, has conducted an exhaustive study of the Upper and Middle Devonian Shales in Columbia's operating territory in Appalachia. The various aspects of this study include gas reserves, depletion characteristics, method of containment, recovery technology and economics.

This study has indicated that the total natural gas reserves of the Appalachian Devonian Shales, in a five-state area of Columbia's principal operations, could be as great as principal operations, could be as great as 285 trillion cubic feet, although the magnitude of recoverable reserves depends on the stimulation technology available or developed and the allowable natural gas price level.

With this indication of large potential reserves, what is the "State of the Art" for the future development of Devonian Shale? In discussion of this potential, the following topics will be presented:Geological DescriptionPotential ReservesMethod of Containment and Depletion CharacteristicsRecovery Technology and Future Planning

Geological Description

The Upper and Middle Devonian Shales are very extensive formations of considerable thickness as shown in Figure 1. The Devonian Shales underlie approximately 100,000 square miles in Kentucky, Ohio, West Virginia, Pennsylvania, and New York. We estimate that Pennsylvania, and New York. We estimate that in this area there are approximately 460 trillion tons of Shale readily accessible to the drill, almost all of which is above 10,000 feet in depth. It should also be noted that the same formations underlie approximately 150,000 square miles in adjacent areas in Michigan, Indiana, Illinois, Tennessee, Mississippi, and Arkansas but will not be considered in this paper. paper.
A Special Application of NMR Logging to Detect Heavy Oil on North Slope Satellite Fields, Alaska
Authors: Campaign Wayne , Waters Doug
Published: December 2007

The occurrence and distribution of heavy oil on the North Slope of Alaska is poorly understood, however it may have economic implications, especially for small, newly discovered fields. Wells with a significant portion of heavy oil in the hydrocarbon column may impact the economic performance of the project.

Nuclear Magnetic Resonance (NMR) measurements provide an economic way of evaluating wells where heavy oil might be encountered. The alternative is expensive coring and testing programs. A simple technique utilizing the deficit in total porosity measured with a NMR tool compared to conventional Neutron/Density cross plot porosity may indicate the presence of heavy oil. The T2 distributions measured from the NMR tool show the point at which lighter oil starts to enter the hydrocarbon column.

The results of a case study from a well on the North Slope where NMR measurements identified a heavy oil zone and confirmed with core and RFT analysis will be presented.
The Development of Heavy Oil Fields in the U.K. Continental Shelf: Past, Present and Future
Authors: Jayasekera A. J. , Goodyear S. G.
Published: December 2007

Historically, most UKCS production has been of light oil, 300 API and above. However, since 1993, a number of heavy oil fields have been brought on production. This paper reviews the history of UKCS heavy oil, the challenges overcome to bring these fields to development, and the future outlook.

The occurrence and distribution of the UKCS heavy oil in place is discussed. A specific correlation to estimate reservoir viscosity from API gravity is presented. Productivity of heavy oil reservoirs is compared with light oil developments, different categories of heavy oil reservoirs are identified, and the use of horizontal or multilateral well technology to achieve acceptable production rates is discussed. The implication of well productivity testing (e.g. extended well testing) of appraisal wells is discussed.

The development challenges that have been overcome in current developments (Harding, Gryphon, Alba, Captain) are reviewed, in particular focusing on well productivity, pressure support, recovery efficiency (management of gas and water coning, areal sweep), and oil water separation. The paper will also review the cost and risk management strategies that need to be adopted to enable the economic exploitation of these heavy oil resources in a demanding environment such as the UKCS.

Finally, the potential for future heavy oil developments is discussed. The scope for IOR technology to increase reserves in heavy oil fields on production by waterflood, or to improve the economics of currently sub-economic fields, is reviewed, focusing on advanced well technology, downhole separation, thermal techniques and conformance control methods.
Non-Darcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity
Authors: Vincent Michael C. , Pearson C. Mark , Kullman John
Published: December 2007

The dramatic effects of non-Darcy and multiphase flow in propped hydraulic fractures have been documented by several authors.1,2,7,9-19 However, many engineers disregard these effects when designing fracture treatments under the assumption that they only apply to high rate wells. This paper shows these effects are significant even in wells considered to be low rate by current industry standards. Ignoring these effects will often lead to inaccurate production forecasts, suboptimal fracture design, and selection of an inappropriate proppant type. These mistakes result in lost revenues which can exceed $2 million per fracture treatment for typical gas and oil well fracture treatments conducted in North America.

Proppant permeability values reported by the industry and used in most fracture design models are measured with a single-phase fluid at extremely low velocities. The laboratory rates stipulated in the American Petroleum Institute3 (API) Recommended Practice number 61 typically correspond to superficial fluid velocities ranging from 0.2 to 2.0 inches per minute. However, in real fractures, the actual fluid velocity may exceed two feet per second, approximately 1000 times greater than in the laboratory measurements. Although the API warned that the lab-measured values would not be realistic under actual fracture conditions, the industry has largely failed to incorporate correction factors into production models to compensate for non-Darcy flow effects.

In addition to non-Darcy effects, the measured proppant permeability values fail to incorporate the effects of multiphase flow. Most gas wells will produce some free liquid (water or condensate), and almost all oil wells will be produced below the bubblepoint of the oil, resulting in substantial volumes of free gas in the fracture. This paper shows that non-Darcy and multiphase flow effects frequently result in an effective fracture conductivity 50% to 98% lower than the reference value obtained from the API testing procedure. Incremental reductions for gel damage and proppant embedment often result in fracture permeabilities or conductivities (the product of fracture permeability and effective fracture width) of 1 to 10% of the published values. This paper examines the mistakes that are likely to be made when ignoring these effects, and estimates the additional cashflow which can be obtained by optimizing fracture design with consideration of multiphase and non-Darcy flow.
Damage-Specific Stimulation Techniques Provide Maximum Deliverability Improvement in Four Gas-Storage Reservoirs—A Case Study
Authors: Guoynes John , Azari Mehdi , Squire Ken , Blauch Matt , Gillstrom Bob , Stegent Neil , Durey Daniel , Jestes Chad , Bielecki Don , Yater John , Clark Randy , Frame Russ , Hopps Kenneth
Published: December 2007

Research has shown that the proper identification of damage mechanisms can improve stimulation techniques used to enhance deliverability in gas-storage wells. The damage mechanisms must be identified before the highest-potential candidate wells and their most effective treatments are determined. Additional data analyses are required to rank candidates properly and design specific treatments to maximize deliverability. Once the diagnostic data are collected and analyzed, an operator must apply the relevant data analysis to the selection of one or more tailored, effective treatment designs. Since many storage companies work from a fixed treatment budget, an adequate well-ranking process must be used for maximum deliverability of dollars spent. The wellranking process can reveal various options for enhancing deliverability with different treatments.

This paper presents case studies from an alliance project in which over 60 wells were diagnosed, treated, and evaluated in four gas-storage reservoirs. Comprehensive diagnostic analyses allowed the development of damage-specific stimulation treatments. New, rigorous processes were developed to evaluate damage and select appropriate treatment options

In this study, damage mechanisms were identified through the use of methods described in a previous Gas Research Institute (GRI) project. Formation damage in each well was quantified by well-test analysis and historical injection/withdrawal-cycle performance matching. Log analysis, petrophysical data, geological data, wellbore imaging, and historical workover data were also gathered as diagnostic treatment-design criteria. The deliverability improvement was quantified for each well based on post-treatment diagnostics. Each study uses several unique treatment options that address a variety of formation damage mechanisms. Treatments were selected to produce the highest deliverability enhancement and maximize the operators’ investment returns.

In Case Study 1, high-pressure jetting, acidizing, and hydraulic-fracturing techniques were used in a deep high-permeability pressure-drive carbonate reservoir. In Case Study 2, high-pressure jetting and damage-specific fluid treatments were used in two shallow-water-drive clastic reservoirs. In Case Study 3, hydraulic fracturing, high-pressure jetting, and extreme overbalanced perforation (EOP) surging were used in a shallow highpermeability pressure-drive clastic reservoir.
Modification of Two Phase Flow Properties by Adsorbed Polymers and Gels
Authors: Zitha Pacelli L.J. , Vermolen Fred J. , Bruining Hans
Published: December 2007

A model for the flow of water and oil in granular porous media treated with polymer and gels is presented. The pore geometry is represented by a triangular duct with a periodically varying section while the topological features are modeled by a statistical network. The mathematical treatment consists of the solution of the hydrodynamic equations in the duct and the up-scaling by a percolation type of approach.

The relative permeabilities of a wetting (water) and non-wetting phases (water and oil or gas respectively) are derived both (a) in the absence and (b) in the presence of the an adsorbed polymer or gels. The preliminary results show that both the flow restrictions at the pore level and the topological changes resulting from polymer adsorption or gel retention contribute to the disproportionate permeability reduction (DPR) for water and oil.

A more systematic study of the effects of the parameters and the comparison of the model with the experiments are required for a full validation of the model.
Utilization of Sand Control and Mechanical Profile Control in Numbi Field Water Injection Wells
Authors: Needham W. J. , Gross S. J. , Pape W. C. , Wilson B. A.
Published: December 2007

The Numbi field is located approximately 20 miles offshore of the Cabinda enclave of Angola. The main producing reservoir in the Numbi field, the 57-05 Upper Vermelha reservoir, is comprised of a stacked sequence of near shore deposits approximately 550 FT thick. The reservoir is highly stratified and faulted, containing a hydrocarbon column that consists of a 200-FT thick oil column overlain by a 240-FT thick gas cap.

The field was discovered in 1982 and placed on production in 1987. A peripheral waterflood project was implemented in 1991 to maintain the reservoir pressure and to improve the ultimate oil recovery. The field reached a peak production rate of over 85,000 BOPD after water injection was initiated. However, poor injectivity, formation sand back-flow into the injection wells, and poor injection profiles prevented the desired level and distribution of water injection from being achieved. These imbalances in injection caused gas cap expansion in some areas, and oil migration into the primary gas cap in others.

Cabinda Gulf Oil Company recently implemented fundamental changes to the reservoir management strategy of the Numbi field to maximize the field's ultimate recovery. Crestal waterflood injection wells have been drilled into the gas cap to balance the distribution of water injection, to increase the voidage replacement ratio (VRR), and to serve as a buffer to prevent the migration of oil into the gas cap. The new injection wells have been successfully completed as screenless frac packs employing curable resin-coated proppant (RCP) for sand control and incorporating multiple packers with injection mandrels for mechanical injection profile control. Pre-job laboratory evaluations were performed with manifold objectives including selection of the optimum curable RCP to be compatible with the proposed fracturing fluid. This was done to provide a frac pack with the greatest conductivity and sufficient compressive strength to withstand the impacts of stress-cycling due to periodic water injection shut-downs. Three dimensional fracture simulations were used to optimize the fracture geometry during the design and implementation of the frac-packs. While the evaluation of the success of these completions is ongoing, results thus far show that the target injection rates are being achieved and that the injection profiles are balanced. The success of this well design is critical for achieving the reservoir management objectives at Numbi.
Kill Procedures to Avoid Formation Damage in the High Rate Gas Wells of an Underground Storage Project
Authors: Oudeman P.
Published: December 2007

To meet winter peak delivery obligations, a depleted gas field in the North Netherlands was converted to a storage reservoir. The 7 5/8″ mono-bore wells were designed for high production and injection rates, up to 280 MMscf/d (8 MMsm3/d) per well from the fully charged reservoir. To produce at such high rates any damage to the formation has to be avoided. A particular concern in this respect was killing the wells e.g. prior to a work-over or in case of an emergency. Inclusion of a side pocket mandrel to land a down-hole circulation device, a potential leak path, was considered undesirable in the design for the high-pressure wells. Hence the wells were to be killed by bullheading. This technique however bears the risk of damaging the productive formations when plugging material is forced into the rock. Therefore it was investigated how the bullheading process could be controlled so that all the gas is pushed back into the reservoir, while avoiding the invasion of foreign material in the productive formations. A dedicated field test to demonstrate the feasibility of the technique was carried out. This test, results and analysis will be discussed.
Particulate Invasion From Drilling Fluids
Authors: Bailey Louise , Boek Edo , Jacques Simon , Boassen Tony , Selle Olav , Argillier Jean-Francois , Longeron Daniel
Published: December 2007

Particulate invasion is one of the primary mechanisms of formation damage caused by drilling fluids. During the initial stages of filtercake growth particles are forced into the formation, building an internal filtercake which plugs the near surface pores. Where bridging is inadequate, the depth of invasion can be considerable. Removal of this internal cake can be difficult, leading to reduced productivity. Better understanding of its properties will lead to more effective cleanup and enhanced productivity.

As part of an EC-Joule funded study into formation damage mechanisms, we have investigated both the invasion of solids and their mobility during clean up. We have systematically investigated the effect of mud particle size on rock substrates of varying permeabilities. The results indicate that formation damage increases with increasing substrate permeability. Substrate permeability was also found to have a marked effect on the initiation of production; flow initiation pressures were greatest on low permeability cores.

Quantitative profiles of solids invasion into sandstone cores for a range of water-based drilling fluids were obtained using scanning electron microscopy/ X-ray mapping (SEM-EDS) and synchrotron energy-dispersive X-ray diffraction tomography (EDD-T). This latter technique, using a synchrotron source, samples the intact core rather than a fractured surface, and gives analytical powder diffraction data, whereas a conventional CAT scanner provides attenuation data only. The effect of back flooding on the invasion profile was then examined, and permeability damage associated with the invasion was also determined. The invasion was compared to damage profiles obtained by core sectioning. Invasion profiles were found to drop quite steeply but fines could be observed deep with in the core. The presence of external cake was found to influence the ease of clean up of the invaded zone.

A deep bed filtration model has been developed for the effect of solids invasion on permeability reduction. This model is compared to the profiles obtained in the invasion experiments.
Core-Flow Experiments With Oil and Solids Containing Water
Authors: van den Broek W. M. G. T. , Bruin J. N. , Tran T. K. , van der Zande M. J. , van der Meulen H.
Published: December 2007

This paper describes core-flow experiments with sandstone cores and artificial produced water. The water contained small quantities of solids in the form of ground sandstone, of oil in the form of droplets, or both solid particles and oil droplets. In the case of water with solid particles the parameters having the largest influence were particles concentration and, to a lesser extent, size. Usually a considerable decrease of the permeability of the first section of the core was observed after an amount of a few hundred pore volumes was injected. For a relatively low particle concentration, in combination with a relatively small average particle size, this decrease was less severe. Injection of water with only oil droplets eventually led to a small permeability decrease in all core sections. Also for injection of water containing both oil droplets and solid particles, the particles concentration appeared to be the most influential parameter. Here the presence of oil usually led to some additional permeability decrease.