bluuebunny/crossref_metadata_2025 huggingface dataset:
Early Reservoir Modeling of Trading Bay Unit Hemlock Formation
Authors: Elliott W.H. , Diver C.J.
Published: December 2007

With considerable foresight, the Working Interest owners in the Trading Bay Unit approved the first performance prediction for the Hemlock reservoir before the first development well was spudded in the Unit. This study and subsequent ones have been made utilizing a high speed digital computer and a program which simulates flow of one, two or three fluid phases in one, two or three dimensions within a reservoir model composed of several thousand grid cells. The fluid flow simulator has been described in published papers. papers. The incentives which prompted the engineering representatives to recommend expenditures for computer simulation and management to approve the expenditures are outlined. In essence; these incentives are proper reservoir management and effective utilization of reservoir energy (either natural or induced) to (1) sustain a high field producing rate, (2) increase the recovery from the reservoir, and (3) minimize investments, particularly by drilling only the required wells. The objectives and major results of the important performance predictions and pressure history matches that have been made are pressure history matches that have been made are reviewed.

A number of problems typical of preliminary studies have been encountered, and additional problems will occur in the future. The problems problems will occur in the future. The problems involve simulating fluid flow in the reservoir, in the well bores and at the surface. Thus far, adequate solutions to the various problems have been obtained and the studies have been successfully completed.

It is concluded that early simulations of historical performance and early performance predictions can be advantageous and profitable. predictions can be advantageous and profitable. However, engineers should carefully outline all objectives, review the five ingredients of an effective application of simulation models as outlined and proceed to recommend a study that may cost tens of thousands of dollars only if economically justified.
Tundra Restoration: Two-Year Response Study of Generic Related Grass Types Introduced onto Disturbed Prudhoe Bay Area Tundra
Authors: McGrogan J.F. , Neubauer J.
Published: December 2007

Disturbance or destruction of the tundra has an adverse effect on its ability to provide protective insulation for the permafrost. A protective insulation for the permafrost. A method for repair is desired.

The tundra is a biological insulating mat, 2 to 4 inches thick, supported by a top soil layer 6 to 18 inches. The soil is made up of silt, sand and organic matter and supports Arctic flora growth. A tundra restoration experiments was initiated on disturbed tundra in May 1969 under the sponsor-ship of the petroleum companies currently operating in the Prudhoe Bay area of the Alaskan North Slope.

This report describes the introduction and establishment of certain winter hardy grasses to the PUT #5 abandoned drill and results obtained after a two year study.

Prior to seeding, a soil analysis was made which indicated severe nutrient deficiencies. This information provided a basis for a special fertilizer formation.

Seeds and fertilizer were applied in June 1969. Unfavorable weather and soil conditions delayed germination for a period of 14 to 18 days. For the same reason, seedling growth achieved only 1 1/2 to 3 1/2 inches by the end of August 1969.

Sampling studies in March 1970 showed that certain grass types on the fertilized plots could be predicted to survive the plots could be predicted to survive the severe winter. This was confirmed in June 1970.

Introduction

The land mass above the Arctic Circle is well known for its permafrost and tundra. In winter, air temperatures can dip below -60 degrees F. and wind velocities can exceed 50 mph. In contrast, the Arctic summer tundra is a biological paradise.

Permafrost is permanently frozen earth material and tundra is the confining skin or vegetative insulating layer on top. The permafrost takes many forums, one of which is permafrost takes many forums, one of which is pure ice just below the surface as shown in pure ice just below the surface as shown in Fig. 1. An active layer between the permafrost and tundra cover freezes and thaws each year. The tundra mat on top controls the thickness of this active layer. this mat supports vegetation.
The Development of a Well Completion System for Deep Permafrost
Authors: Blount Elmo M. , Prueger Nick J.
Published: December 2007

The "systems approach" when used in developing a well completion system for producing wells through deep permafrost demonstrated producing wells through deep permafrost demonstrated its value in adapting well operations to unique circumstances and environments. This method of problem solving, often used by aerospace and problem solving, often used by aerospace and defense industries, provides the discipline for an integrated group of specialists in considering the effects of the modification of specific equipment and components on the total system.

The completion system for North Slope wells uses 700 ft of 2-1/2-in. thick polyurethane insulation around 7-in. OD casing to keep the upper 500 ft of permafrost from thawing while the well is producing at high rates for more than 20 years. Additional insulation can be added at a later date from 700 ft to the bottom of the permafrost if it is necessary to further protect the well by limiting the thaw radius. protect the well by limiting the thaw radius. The weight of all the casing strings is transferred down hole rather than through the wellhead. A packing gland-type wellhead allows the production casing to "grow" due to thermal expansion.

Illustrations depict three different approaches considered for completion systems of North Slope wells, a schematic of Mobil's completion system, thaw profiles for insulation to 700 ft and for insulation to 2,000 ft and an arrow diagram showing the interrelations of drilling and production problems which must be considered when adapting a completion system to a unique environment.

Introduction

With exploratory efforts increasing in remote areas and unusual environments, well completion systems are becoming more complicated to adapt to these environments. Altering a conventional completion procedure or piece of completion equipment to cope with a specific problem can often create unforeseen problems in problem can often create unforeseen problems in other parts of the procedure. When conventional procedures are changed to solve a particular procedures are changed to solve a particular problem, a technique is needed which will help problem, a technique is needed which will help view the well as a complete system. One such technique, the "systems approach", used recently by space- and defense-oriented industries to help organize and coordinate problem-solving assignments, was used by Mobil to develop a well completion system for North Slope wells.

At first glance one may think this is what is done subconsciously - or may ask what is the difference in the systems approach and the tried and proven scientific method.
Transportation Of Oil From The Arctic The Trans Alaska Pipeline
Authors: Patton E.L.
Published: December 2007

A group of seven oil companies has formed the Alyeska Pipeline Service Company to design, construct, operate and maintain the trans-Alaska pipeline system. The total pipeline will be approximately 789 miles long, pipeline will be approximately 789 miles long, some 641 miles of which will be across Federal lands. The project will include pump stations, camp sites for use during construction, airfields for use during both construction and operation of the line, a communications system, and material sites for construction and access roads. The terminal site at Valdez will consist of a tank farm and dock facilities from which ocean-going tankers will transport crude oil to markets. Prior to construction of the pipeline north Prior to construction of the pipeline north of the Yukon River, a road will be built for access and the movement of equipment, materials and personnel during pipeline construction activity. This road, proposed to become a part of the State of Alaska Highway System part of the State of Alaska Highway System will be approximately 373 miles in length, of which about 365 miles will traverse public lands. Of the approximately 586,000 square miles of land in Alaska, the project will utilize about one one-hundredth of one percent of the total. percent of the total. The project is now more than a year behind its original schedule as a result of a court injunction stemming from the National Environmental Policy Act of 1969, and an injunction based on Native claims to Alaskan land.

PROJECT DESCRIPTION The major components of the system will be the pipe and associated structural elements, an origin station, pump stations, terminal facilities, a communication system, a pipeline monitoring system, a seismic monitoring system, and access roads.
Alaska and the International Oil Scene
Authors: Symonds Edward
Published: December 2007

It is a great pleasure to be invited to Anchorage to address the first Alaska Regional Meeting, The Alaska Oil scene, of the Society of Petroleum Engineers of AIME. My last visit to this city was almost 10 years ago. At that time I tried to keep my mouth shut. But I could not help believing - even in the Cook Inlet perspective of those days - that this state was a very exciting oil province. Today we recognize it as probably the greatest in the history of the U. S.

Since that early visit the demand problems in the oil industry have certainly been multiplying. I have some slides showing the scale of demand growth and the part that we now expect Alaska to play in meeting it.

There was a time when the industry's professional pessimists used the Prudhoe Bay professional pessimists used the Prudhoe Bay discoveries as proof that the industry was in for new troubles. The theory was that at least 15 billion bbl of recoverable oil in the Prudhoe Bay area would give rise to a new source Of about 2 million B/D of production by 1980. This would pour into the West Coast market, more than doubling its present supply. Together with some increase in production from other parts of Alaska and with California continuing parts of Alaska and with California continuing to produce about 1 million B/D, local needs would be unable to absorb the new supply. With Canadian imports remaining economically attractive, and with no obvious way of transporting crude oil to the big markets of the Midwest and the East Coast, it was argued that nearly 1-1/2 million B/D would be hunting desperately for buyers on the West Coast. As a result, the price structure would crumble. Production in price structure would crumble. Production in the Southwest would have to be cut back … or so said the pessimists.

This was a gloomy outlook for the oil companies. And we broadly agree with the basic statistics that I just mentioned. But we do not agree about Alaska's impact on the industry. In fact, the oil shortages that appeared last summer made it clear how greatly the pessimists had misjudged the outlook.

Today, we are much more conscious than we used to be of the obstacles to North Slope development. Ever since Seward's $7 million "folly" in 1867, many people have had mixed feelings about what Alaskans call outside "spoilators". The gold discoveries on Bonanza Creek in the Klondike in 1896, the Kennecott discovery in the Copper River basin in 1900, and the excesses of the fish trappers in the first half of this century, all gave a very solid basis to fears like those expressed by Thomas E. Kelly of the Dept. of Mineral Resources of Alaska. At a meeting of the Society of Petroleum Engineers not much over a year ago, he talked about the after-math of exploitation as a "tragic scene on the Alaskan landscape."
Pipelining and People in the Arctic
Authors: Hurd Lee G.
Published: December 2007

It seems certain that the decade of the '70s will see some dramatic changes in energy supply and delivery systems throughout North America. Energy requirements are accelerating and the increases in traditional sources of supply are lagging behind.

Several new energy sources will be investigated and some tapped. This paper describes the study of one such new source: the connection by a pipeline into the Arctic of new reserves of gas in Alaska and northern Canada with markets in the U.S. and Canada.

Reserves which would support such a pipeline may be proved now and the potential pipeline may be proved now and the potential for additional reserves in the Arctic is more than encouraging.

Three groups, one of which is The Northwest Project Study Group, have announced study projects. The Northwest group has committed over $12 million to research and studies and is well underway with its work.

Pipelining in the Arctic will be an unique challenge. Permafrost, in all its variations, exists under the soil through nearly half the length of the pipeline. In addition, massive ice lenses and vertical ice wedges will be encountered. Any disturbance of the thin insulating organic surface layer will start thermal erosion in many areas.

The Northwest Group is investigating the feasibility of carrying refrigerated gas in a buried line and to evaluate the scheme has had constructed a pipeline test facility in the Arctic. The facility includes long sections of 48-inch diameter pipe through which air at controlled temperatures is circulated. The test program will evaluate pipe stability in high ice content permafrost; will test foundation types; will investigate surface restoration methods, drainage problems, etc.; and will include investigation of construction practices.

A detailed knowledge of the unique arctic ecology will be essential. Ecologically sensitive areas must be identified and respected. Wildlife species must be understood and undue disturbance avoided.

The native people living along the pipeline route, while few in number, must be pipeline route, while few in number, must be included in the plans and programs of such a pipeline project. pipeline project.
Oil Extraction, Urban Environment, And City Planning The Los Angeles Experience
Authors: Branch Melville C.
Published: December 2007

There has been urban oil exploration and production in Los Angeles, California, for 75 years. production in Los Angeles, California, for 75 years. Regulation of these activities has developed progressively over the years without making them progressively over the years without making them economically impossible. Today, improved city planning and greater urban environmental protection planning and greater urban environmental protection call for additional policies and requirements This review of Los Angeles experience and recommendation for the future are intended to assist the many communities in the world which are or will be built over oil fields. By applying this experience modified to fit the local situation, cities elsewhere can establish policies, laws, and regulatory conditions which permit urban oil operations consistent with sound city planning, urban development, and favorable local environment.
Insulated Gravel Embankments for Arctic Road Construction
Authors: Condo A.C. , Burt Glenn R.
Published: December 2007

Permafrost creates special engineering problems for the design, construction and problems for the design, construction and maintenance of embankments. Lack of knowledge about permafrost and environmental conditions has resulted in tremendous maintenance costs as well as relocation or abandonment of highways, railroads and other embankment structures. Therefore, careful consideration must be given to the design and construction of embankments to be placed on permafrost.

Since the spring of 1969, ARCO Chemical Company has been working on embankment design and construction methods which could serve as alternates to the conventional (5–6 feet of gravel) method of embankment construction on the North Slope. Study and research has resulted in the development of ARCOFOAM Insulated Embankment Systems which are technically (thermally and structurally) capable of being used as an alternate method in the design and construction of Arctic Embankments.

Introduction

The problems of permafrost degradation must be considered in the design of Arctic and sub-Arctic embankments. Two basic design methods which may be utilized are the active and passive techniques. The active method eliminates the permafrost by excavation and fill. An example would be stage construction of sub-Arctic roadways. These are built by placement of fill and constant maintenance placement of fill and constant maintenance over a period of years as melt and subsidence of the permafrost occurs. On the North Slope of Alaska, which is underlaid with more than 1,000 feet of permafrost, the active method is impractical. The passive method prevents permafrost degradation by keeping prevents permafrost degradation by keeping it in a continually frozen state so there will be no melt and subsequent subsidence. Therefore, the passive method controls the design of roads, airfields and other embankments in the Arctic.

Subsurface features of prime concern in Arctic embankment work include soil type, water content, permafrost which, when melted, causes subsidence or settlement.

We can establish the mean annual air temperature, mean annual air freezing index, mean annual air thawing index and the amplitude of temperature fluctuation however, thermal design is related to the temperature that occurs at the soil-air interface. This temperature is affected by numerous items, such as depth of snow, soil type, wind and evaporation cooling rates at the interface.
U. S. Hydrocarbon Finding Cost
Authors: Howell F.N. , Merklein H.A.
Published: December 2007

Introduction

It is the purpose of this paper to develop a trend of hydrocarbon finding costs, spanning the period from 1938 to 1968, and to compare this trend with others that have been occurring in the petroleum industry. Such a comparison of long-run trends may be useful as an early-warning device capable of detecting impending difficulties that are to be expected in the supply structure of domestically produced hydrocarbons.

Finding costs are defined as total exploration expenditures in a given year, divided by the total quantity of hydrocarbon reserves that have been discovered as a result of these expenditures. Thus the two major items that need to be considered are exploration expenditures and reserve discoveries. These will be discussed in that order.

EXPLORATION EXPENDITURES

One part of the U. S. hydrocarbon finding costs, namely total exploration expenditures, is straightforward and presents no great conceptual problem. However, as will be seen later, a substantial amount of statistical data manipulation and interpolation is required for a reliable estimate of this factor.

Exploration exploration, as used in this study, consist of the following subcategories:

Drilling and equipping exploratory wells Acquiring undeveloped acreage Lease rentals Geological and geophysical expenditures Test well contributions Land Department (leasing and scouting) Other, including direct overhead

Collection and evaluation of data on each of the above subcategories and, for that matter, on other petroleum statistics, is accomplished each year by a joint effort of the American Petroleum Institute (API), the Independent Petroleum Association of America (IPAA), and the Mid-Continent Oil and Gas Association (MCOGA). This Joint Association Survey is prepared annually to provide information on finding, developing, and producing hydrocarbons by the oil and gas producing industry in the United States.
Optimization of Sucker Rod Replacement
Authors: Powers Maston L.
Published: December 2007

A technique has been developed to optimize sucker-rod string replacement decisions. The basis for this optimization assumes that the failure frequency expectation of sucker rods increases with time at a variable rate approximating a Gaussian curve throughout their usable life. At some point in time the maintenance cost of continued operation of a fatigued rod string exceeds the capital cost and associated maintenance cost of a replacement string. A mathematical expression representing this optimum replacement point was developed and solved for the time interval between sucker rod failures. The resulting equation can be applied to a partial replacement as well as a complete replacement rod string. A graphical solution was developed to implement the optimization technique for routine field use.

Introduction

A need for improved criteria for making sucker-rod string replacement decisions became evident while making a detailed study of operating costs and field practices in the midcontinent area. It was found that sucker rods were being replaced on as many bases as there were individuals making replacement decisions.

During the time interval for which sucker-rod replacement data was compiled, Nov., 1969, through Aug., 1970, it was found that fatigued rod strings were being replaced after an average of 7.6 failures. Wells that exhibited symptoms of specific mechanical problems were excluded from this analysis. For example, instances of chronic joint failures were attributed to improper makeup practices rather than fatigue.

Judgment indicated that the observed replacement practices needed improvement. An engineering basis for economically optimizing sucker-rod replacement decisions was therefore pursued. pursued.

Basis of Optimization Technique

Performance of sucker rods is affected by numerous well conditions such as maximum rod stress, stress range, pumping speed, corrosivity of the environment, and a variety of mechanical problems. Thus, each well can be expected to problems. Thus, each well can be expected to exhibit unique behavior. However, by assuming that individual well conditions remain constant during an analysis period, sucker rod performance can be generalized. performance can be generalized. For any combination of constant well conditions a properly designed sucker rod string will initially have relatively infrequent failures. As a result of cyclic loading in normal use, the failure frequency expectation of the string should increase with time in a rough approximation to a Gaussian curve, as depicted in Fig. 1.
Finite Element Analysis of Single Well Backflow Tracer Test in a Homogeneous Reservoir
Authors: Chase Curtis
Published: December 2007

The single well backflow tracer test, in which one tracer is injected into a reservoir and then monitored at the same well as the fluid is withdrawn, is modeled for a homogeneous infinite reservoir. A numerical solution to the partial differential equation modeling the system partial differential equation modeling the system is obtained by the method of finite elements. For equivalent accuracy this method appears to give solutions in considerably less computer time than that required to solve the same problem by finite differences. An approximate analytical solution is also obtained.

The mathematical model contains three dimensionless parameters. Unfortunately, the injection of a single pulse of tracer does not supply enough information to uniquely determine these parameters. One method of determining all three is to inject three distinct pulses of tracer into the reservoir and allow each pulse to penetrate a different distance.

Partitioning of tracer into a stationary oil phase or onto the surface of reservoir rock can cause a significant increase in the amount of dispersion observed at the well bore. An example is presented which illustrates these sorption effects.

PURPOSE AND SCOPE PURPOSE AND SCOPEIn the simplest single well backflow tracer test a pulse of tracer is injected into a reservoir. After a period of time flow is reversed, and tracer concentration is monitored as the carrier fluid is withdrawn. Proper interpretation of the well bore tracer concentration response during withdrawal offers a possible means of evaluating certain reservoir properties in situ. The advantage of in situ determination of reservoir properties lies in the fact that the results are representative of a larger reservoir volume than are results from logs or core samples.

Properties primarily of interest which might be obtainable from a backflow tracer test are (1) reservoir residual oil saturation and (2) the parameters which characterize dispersion. Knowledge of the dispersion parameters is necessary in order to correctly evaluate possible secondary recovery projects in which mixing of the displacing and displaced fluids takes place because of dispersion.

The tracer concentration within the well bore is governed by the convective-diffusion equation.
New Oil Gelling Systems Prevent Damage in Water-Sensitive Sands
Authors: Kucera C.H. , Smith C.F. , Braunlich F.H.
Published: December 2007

Development of viscous fracturing fluids has renewed interest in fracturing with oil base materials. Oil, once the primary frac fluid, was displaced when aqueous systems allowed more flexibility and safety. Water-sensitive and some other easily damaged formations were victims of this change since most of the new developments in fracturing technology could not be applied. Recent developments have led to gelled oil systems which allow injection rates and prop carrying capacities previously unattainable with other oil base systems. These gelled oil systems can be continuously mixed to carry 10–20 sand concentrations in excess of five pounds per gallon at rates of 20 barrels per pounds per gallon at rates of 20 barrels per minute down 2-1/2 inch tubing. These systems do not damage water sensitive formations. The gel is broken by an internal breaker system.

This paper describes the chemical development of the new gelling agents and their application in many experimental treatments. Rheological comparisons with other viscous frac fluids are shown and other potential applications of the systems are discussed. These include use as drilling fluids, workover fluids and packer fluids where formation damage is critical.

Introduction

The choice of fluids used in fracturing and their application has been cyclic in nature. Originally fracturing was done with oil exclusively. With later development of horsepower, friction control, desirability of large volume treatments, and emphasis on treatment safety, it became advantageous to use aqueous fluids, including brine, water and acid. The switch to aqueous fluids was so complete that by 1968 oil base fracturing fluids accounted for less than 10 per cent of the total volume of frac fluids pumped in the United States. pumped in the United States. With the general swing to water based fluids, research and development effort during the past 15 years has been devoted primarily to the improvement of aqueous frac fluids. Throughout this time, however, there has remained a need for oil-base fluids to treat formations which are water sensitive. Injection of aqueous fluids into these formations often fails to provide stimulation benefits and may result in a productivity decrease. Even the use of potassium chloride or calcium chloride has not been successful in fracturing many of these zones.
An Investigative Study on Horizontal Well and Extended Reach Technologies with Reported Problem Areas and Operational Practice in North America and Europe
Authors: Ikeda S. , Takeuchi T. , Crouse P. C.
Published: December 2007

In 1994 and 1995, a study was initiated to investigate developments, activity, and philosophies of the larger oil and gas industry in implementing horizontal well and extended reach technologies. To date, North American and European operators, contractors, service companies, government authorities, and educational institutions have been interviewed directly along with the development of data resources and references. Over 100 people shared in direct interviews, constituting 13 operators in Europe, 14 operators in North America, 2 drilling contractors, and 5 major manufacturing/service companies. Over 40 person-to-person interviews were accomplished in North America and Europe. Any company specific information shared in the interviews were given in confidence in that the companies would not be identified in any summary results; thus this paper refers to industry findings. Interviews along with approximately 1000 references and industry well information provided a detailed look at horizontal well and extended reach technology industry along with application strategy and philosophy.
Second Generation Synthetic Fluids in the North Sea: Are They Better?
Authors: Friedheim J. E. , Conn H. L.
Published: December 2007

At the beginning of the 1990's, three synthetic type materials were introduced – esters, ethers and polyalphaolefins. Now after heading towards the last half of this decade, a new generation of synthetics are gaining popularity – linear alpha olefins and isomerised olefins. Another base fluid, linear paraffin, which can be considered pseudo-oil rather than synthetic, is also making an impact. Each of these materials have similarities as well as differences both as base fluids and drilling muds.

North Sea applications of synthetic-based muds highlight the major aspects which not only delineate the first generation of fluids from the second but also the various fluids themselves. Each area – the United Kingdom, Norway, and the Netherlands – not only have different marketplaces, but also different emphasis on the many facets of environmental as well as health and safety concerns. This variance from country to country provided the impetus for the introduction of these various fluids.

This paper provides an overview of these second generation fluids and deals with their technical, environmental, and economical status as it relates to the North Sea drilling area. It will also discuss these second generation fluids in light of their predecessors and emphasise the differences. Details will be provided into the chemistry of these second generation fluids and actual field data will be provided to illustrate their effectiveness.
Land Rig Move Between Central Asia (Kazakhstan) and Eastern Europe (Romania)
Authors: Rabier J P
Published: December 2007

The FORASOL NATIONAL 1625/3 rig was mobilized from a west European port to the rig site in central KAZAKHSTAN (near AKTIUBINSK) in 1993. The rig was transported by ocean and river ship (5), block trains (5) and 250 truck loads.

A survey was of course required in order to determine the best routing in function of port facilities (transhipment), availability of cranes and handling equipments and seasonal influences. This survey required several months work..

The main caracteristics of our equipment.
The Challenges of Drilling Wells Approaching 40,000 ft.
Authors: Norman Monica , Tveit Leon , Kalvenes Øystein , Humblen Jarl Ove
Published: December 2007

This paper describes the results from an extensive, joint, development project between Norsk Hydro A/S and Anchor Drilling Fluids A/S, aimed at identifying the potential problems associated with drilling wells approaching 40,000 ft., mainly focusing on the drilling fluid aspects.

The major obstacles related to drilling such extremely long wells were identified as:Drilling equipmentFluid related problems:–Pressure losses–ECD effects–Wellbore stability–Lubricity–Hole Cleaning

The project also incorporated the development of a new, environmentally friendly, synthetic oil based mud system, and further developments of existing systems in order to solve the identified fluid-related problems. Results from field tests are reported.
Field Validated Hydraulic Model Predictions Give Guidelines for Optimal Annular Flow in Slimhole Drilling
Authors: Cartalos U. , King I. , Dupuis D. , Sagot A.
Published: December 2007

Accurate prediction of annular flow is of primaiy importance in slimhole drilling. A model was developed that better represents actual annular configurations. It accounts for axial variations of drillpipe eccentricity and for effects arising from drillpipe rotation. The model is validated with data obtained from 3 industrial slimhole wells (4"3/4 and 3"3/8 phases). Based on model predictions, guidelines are given to define flow parameters and to adapt fluid rheology in order to obtain optimal hole cleaning under safe drilling conditions.
Analysis of Carbonate Dual Porosity Systems from Borehole Electrical Images
Authors: Newberry B. M. , Grace L. M. , Stief D. D.
Published: December 2007

Many productive carbonates have dual porosity systems with widely varying proportions of primary and secondary porosity. The secondary porosity may contain vugs, molds and fractures. Most interpretation methods rely on traditional resistivity and porosity logs. These often fail to produce results consistent with production because of the complex nature of the dual-porosity carbonate. Borehole electrical images provide both the small-scale resolution and azimuthal borehole coverage to quantitatively resolve the heterogeneous nature of the porosity components. The primary assumption for this technique is that the resistivity data from the electrical images are measured in the flushed zone of the borehole. Then, the electrical images can be transformed into a porosity map of the borehole. Automated analysis of this porosity map, windowed over short intervals, provides a continuous output of the primary and secondary porosity components. This method has been applied to a variety of carbonate formations where conventional log analysis has usually failed. The predicted results compare accurately with the actual production.
Sequence Stratigraphic Model and Geology/Reservoir "Flow Unit" Study Improve Profitability and Recover Additional Reserves at the Sharon Ridge Canyon Unit
Authors: Kane T. V. , Henderson R. P.
Published: December 2007

The creation of a sequence stratigraphic geologic model of the Sharon Ridge Canyon Unit (SRCU) has significantly improved reservoir description in this highly stratified carbonate reservoir. The enhanced vision of geologically continuous sequences is dramatically better than that provided by traditional 2-dimensional (2D) lithostratigraphic (log cross section) correlations. The much improved accuracy of predicting geologic continuity has enabled engineers and geologists to recommend effective programs to optimize current waterflood operations. The combined effect of developing a sequence stratigraphic model, identifying the reservoir "flow units" associated with continuous sequences of pay and optimizing the depletion of these "flow units" has improved field production rates and resulted in a reduction in operating expenses.
Multi Zone Completion Design Considerations
Authors: Aldridge Don
Published: December 2007

Very often, a wellbore penetrates numerous geologic zones of interest. An optimum completion design addresses a method of isolating these zones while protecting the reservoir for future exploitation. A common practice is to utilize two or more packers for efficient zonal isolation. When designing such a completion, a number of conditions and phenomena must be considered. These include, among others: thermal expansion; pressure changes; piston effects, and their resultant force and/or length changes. This paper outlines some of the factors that must be taken into consideration, then presents specific challenges and viable solutions for typical multitandem completion designs.
Wireless Telemetry for Transmitting Pressure and Temperature Data on a Drillstem Test
Authors: Holder Kent , Heine Dick , Copeland David
Published: December 2007

An openhole drillstem test (DST) simulates producing conditions to help operators determine if a formation may be commercially productive during the drilling phase of the well. A DST isolates a formation with packers, and a tester valve opens to expose the formation to lower hydrostatic, which causes the formation to produce. After a predetermined flow period, a downhole shut-in valve closes to start a buildup period. The sequence of flow and closed-in periods is repeated as required.

Testing can provide information such as effective perme-ability, skin damage, formation pressure, flow rate, fluid type, and radius of investigation. Effective permeability, skin damage, and formation pressure calculations are possible only if the buildup period is long enough to reach Horner data.1 The duration of close-in periods is generally based on rule of thumb, bubble-hose response, or field experience. Surveys of current DST reports indicate that 30% of formations tested were not shut in long enough for Horner data to be obtained. The best method to determine the length of flow and shut-in periods is to monitor the pressures real-time at the surface. Wireline surface readout is available but is costly and poses risks, since the wireline is in the well. This paper discusses the operation and application of a new wireless telemetry tool that transmits real-time pressure and temperature readings to surface on an openhole DST.
Process Changes Improve Fracture Treatment Designs in the Hugoton Gas Field
Authors: Hecker M. T. , Downie R. C.
Published: December 2007

Hydraulic fracturing has been used extensively for well stimulation in the Hugoton gas field since the 1960's. Through continuous improvement efforts, and a renewed importance placed on quality data collection, stimulation costs have been significantly reduced since 1991 by pumping smaller single stage fracture treatments without sacrificing gas production. Better control of fracture growth has lead to initial savings in capital investments as well as improving ultimate gas recovery.
Development of the Cleveland, Tight Gas Sand, in the Texas Panhandle
Authors: Lovett W. T. , Atkins R. J.
Published: December 2007

The Cleveland Formation exists across a large area of the Texas Panhandle. This is a tight gas sand with very low permeability.

The two major fields in the Cleveland Formation are the Bradford and Ellis Ranch. These fields were discovered in the late 1950's and developed on 640 acres per well originally. They were later downspaced to 320 acres and recently have been downspaced to 160 acres per well.

Work by a large independent producer in conjunction with the Gas Research Institute has resulted in more efficient and effective development of the Cleveland Formation. Field histories, regulatory difficulties, drilling cost reduction, fracture technology, and economics are discussed; along with case histories and comparison of techniques.

Increased reserves and profitability in the Cleveland Formation have been realized through this effort.
Prediction of Low-Frequency Offshore Structure Response to Irregular Waves Using Linear and High-Order Wave Theories
Authors: Ramos R. J. , Zhang J.
Published: December 2007

The predicted responses of an offshore structure when the wave kinematics are computed from different estimation methods can change significantly. The sometimes controversial results have recently motivated the development of a new methodology for random wave kinematics prediction known as Hybrid Wave Model (HWM). In this paper, the performance of the new methodology and other methods currently used for kinematics prediction was tested. The (surge) response of two offshore structures designed specially for deep-oil production was estimated using three methods (Hybrid Wave Model, Wheeler "Stretching" and Linear Extrapolation) and compared with the corresponding laboratory measurements. The wave forces were computed from the conventional Morison Equation evaluating the ambient wave kinematics from the wave elevation measurements and the response was computed using a numerical scheme based on a Finite Element time integration technique (Newmark-beta method).

The comparisons between measured and predicted responses using kinematics calculated from the Hybrid Wave Model showed excellent agreement, specially for the low frequency components, while those using methods based on linear modifications rendered poor underestimations. The low frequency (peak) responses of these deep-water offshore structures were found to be greatly dominated by very low frequency wave excitations, which are mainly due to the wave-wave interactions. This work will show the necessity of high-order methods to evaluate irregular wave kinematics and induced responses.
The Adon Road - An In-Depth Gel Case History
Authors: Smith J. E. , Mack J. C. , Nicol A. B.
Published: December 2007

The Adon Road Unit is a Minnelusa Reservoir located in the Powder River Basin of northeast Wyoming. Permeabilities in this unfractured Minnelusa sandstone range from 10 to 1200 md, with an average of 320 md. Oil viscosity at the bottom hole temperature of 175°F is about 5 cps. Polymer flooding was initiated at the beginning of the waterflood to correct the high perm variation and adverse mobility ratio. Because of the high permeability variation, in-depth colloidal dispersion gels (CDG's) gels were used to initially sweep and block the high permeability rock to subsequent water and polymer injection. CDG's consist of polymer with aluminum citrate crosslinker, injected as a homogeneous solution. A total of 564,948 barrels, or 8.03% PV, of CDG were injected at an average polymer concentration of 268 mg/L over 20 months. The CDG was followed by 556,800 barrels, or 7.91 % PV, of uncrosslinked polymer at an average concentration of 150 mg/L, injected over 17 months. Following the gel and polymer program, straight water was injected.

The polymer and gel program has resulted in more oil recovered with less water handled. Total recovery through January, 1995, was 45.2% STBOOIP after 32.3% PV total water injection, compared to 27% STBOOIP typical for straight Minnelusa waterfloods at the same cumulative water injection. Ultimate recovery has significantly exceeded the original model projections. The details of gel and polymer placement, field response and monitoring are reported. Original assumptions about the reservoir and chemical flood are explored to determine why actual performance exceeded projections.
A Systematic Laboratory Core and Fluid Analysis Program for the Design of a Cost Effective Treatment and Cleanup Guidelines for a Produced Water Disposal Scheme
Authors: Ohen Henry A. , Nnabuihe L. , Felber B.J. , Ososanwo Duni , Holmgren C.M.
Published: December 2007

A practical and systematic technique for the determination of cleanup guidelines based on laboratory rock and fluid studies is presented. This method was employed in the preliminary design of a water disposal scheme requiring a high rate (30,000 bpd per well) into a shallow aquifer system in the Niger Delta. A description of the laboratory tests employed in the evaluation of the potential and the degree of impairment from the different mechanisms is presented along with interpretations and scaling of laboratory data to field operating conditions. Injectivity impairment resulting from relative permeability effects due to increased oil saturation over time, emulsion block, particulate plugging from suspended solids and in-situ mobilization, and clay swelling were quantified by time dependent pseudo skin factors.

A composite time dependent pseudo skin was derived from the combination of the individual components obtained from specially designed laboratory analytical tests on representative core and fluid samples. The results were extrapolated to field conditions using standard scaling techniques and employed as a basis to determine water treatment requirement and periodic cleanup guidelines.

This approach enabled the conceptual design of a pilot water disposal scheme based solely on laboratory study of representative produced water, formation water and aquifer rock samples. Specification for water clarification, filtration, formation pre-treatment guidelines and cleanup schedule for the disposal well in the target aquifer system were made apriori to field implementation.

Introduction

The quality of the source water (produced or surface) is of prime concern in any water injection or disposal project. Clean water is particularly important in wells requiring sustained injection at high rates. Oil and suspended solids must be held to a concentration below maximum tolerable limits to maintain injectivity for an extended period of time. The objective of this water disposal study was to assess the feasibility of subsurface disposal of produced water from an inland dehydration station. The study was based on the current need to dispose of 175,000 bbl/d and the possible future need to dispose of up to 300,000 barrels per day of produced salt water by the year 2008.

The following four major tasks were pursued in the study;Identification of candidate aquifer system(s) for the disposal of the produced waterCharacterization of the aquifer system, compatibility studies, and development of injectivity criteria

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Evaluating Waterflood Potential in a Morrow Sandstone Reservoir
Authors: Mohan Hitesh , Burchardt Per , Willhite G. Paul , Reynolds Rodney R. , Jensen Mike
Published: December 2007

The Stewart Field project is a demonstration project being conducted in Kansas under the U.S. Department of Energy’s Class 1 Oil Program for fluvial dominated deltaic reservoirs. The objective of this project is to address waterflood problems in Morrow sandstone reservoirs in southwestern Kansas. The general topics addressed are 1) reservoir management and primary drive performance evaluation, and 2) the demonstration of a recovery process involving currently available technology which can be used to enhance waterflood recovery and increase reserves. The project is being conducted in a cooperative manner, involving University of Kansas scientists, engineers, and geologists and independent oil operators.

Project results to date are 1) the development of a comprehensive reservoir database using personal computers, 2) the completion of a simulation study to history match the primary production, 3) the simulation of waterflooding and polymer flooding, 4) an economic analysis to assist in identifying the most economical waterflood pattern, 5) completion of laboratory analysis conducted on reservoir rock, 6) unitization of the field so that a field-wide improved oil recovery process could be implemented, 7) design and construction of waterflood facilities and 8) initiation of the waterflood.

Current activities and future plans consist of the operation of a waterflood installation utilizing state-of-the-art technologies in an attempt to optimize secondary oil recovery. Production and reservoir data will be analyzed using reservoir characterization techniques and by updating the existing reservoir simulation. The analysis of results will be utilized to optimize the waterflood plan and flooding techniques to maximize the secondary oil recovery. This project was awarded the "Best Advanced Recovery Project in the Mid-Continent" for 1995 by Hart’s Oil and Gas World.