bluuebunny/crossref_metadata_2025 huggingface dataset:
Cerro Negro Development: A Success Story...From Inception To Execution
Authors: Vasquez Milton
Published: December 2007

The Cerro Negro project, located in the Orinoco oil belt of Eastern Venezuela, first began in 1997 with the drilling of an appraisal program and the longest horizontal section ever drilled in Venezuela. This startup led to a 1½ year drilling campaign that resulted in 121 drilled and completed wells, and up to 129,000 BOPD (UCO) flowing down the pipeline. New technologies in drilling, completion, and artificial lift were applied to extended reach horizontal wells to efficiently develop the Cerro Negro field. Applications of these technologies include: 1) development of two fit- for-purpose rigs capable of skidding between well slots and spudding a new well in 1½ hrs; 2) implementation of a stratigraphic well program to define difficult geologic targets utilizing a coil tubing drilling unit; 3) development plans for 2-D and 3-D wells drilled as stacked forks into three distinct reservoir sands; 4) application of the latest geosteering technology; and 5) development of high capacity progressing cavity pumps for artificial lift. The concept of a learning curve approach was also implemented by setting target and stretch performance goals for the project. Key success factors for the program include a strong communication system between the operator and all suppliers, continuity of services and manpower supporting engineering and operations including dedicated equipment and an inhouse directional drilling representation, continuous improvement of operations, and application of dynamic benchmarking concepts. This program has achieved a 30% reduction in drilling and completion (D&C) costs and a 38% reduction in D&C time.
Floating Production Systems
Authors: Hamilton Jack Rayburn , Barrack James White
Published: December 2007

This paper considers some of the major problem areas which are being encountered in offshore oil and gas developments. The case is then presented for the consideration of floating production systems as an alternative to fixed platform solutions.

Floating production has been in operation for some years. The concept has been demonstrated as being both practical and economically attractive. The principal basis for development has been the use of converted offshore drilling vessels. Such proven technology is now being supplemented by a number of proposed designs based on specific application and wider ranging production capability. A review is given of the available structures.

The principal component parts of floating production systems in general are considered. Principal requirements, limitations and areas which require development are given with a view to the achievement of improved design and performance.

In conclusion the advantages of floating production systems are summarized and recognition is given to the potential which they present for marginal field development, early production and deep water applications.

Introduction

In the face of the continually recurring challenges of deeper (Fig. 1) (Ref. 1), rougher water and rapidly rising costs, the offshore oil and gas industry is moving towards a new generation of production systems. These are the floating production systems (FPS) where rigid support from the seabed has been replaced by a flexible mooring system which creates less sensitivity to water depth, economic attractions and a new marriage of offshore technologies aimed at solving some current offshore problem areas.

With the original single-purpose piled steel platforms as the first generation of offshore structures, the later multi-purpose steel or concrete platforms as the second generation, so floating production platforms may be viewed as the third generation of this family tree.

Such a shift in the development emphasis from fixed to floating platforms is a fundamental variation in the philosophy of offshore field development. Competition and reaction against high costs have initiated a need for change and what had become conventional fixed structure offshore technology is likely to be joined by floating systems, subsea systems and hybrid combinations of these. Fixed structures gained their foothold in shallower waters. They are likely to retain their application in such areas but in the move into the recovery of deeper water reserves, floating production systems have large potential advantages.

The FPS concept can be defined as a buoyant platform structure moored over seabed wellheads with the two connected by a flexible production riser. The platform may be either a conversion of a floating structure built for some other purpose or one which has been designed and built to specification. Currently the former (semi-submersibles or tankers) have been established due to availability, established performance and low relative cost while the latter exist on many drawing boards awaiting acceptance by the industry.
Some Engineering Aspects Of Offshore Loading Systems
Authors: Olbjorn Egil Hans , Torset Odd
Published: December 2007

The presented paper covers essential aspects and requirements for offshore loading systems.

Response characteristics of typical concepts and associated design forces for the mooring and anchoring systems will be discussed. The need for model tests compared to anchoring and mooring systems in respect to strength and durability.

The governing factors for the lifting efficiency including operational limitations with respect to weather conditions are considered.

The paper concludes with some considerations from the certification point of view.

Introduction

Offshore loading systems for the initial temporary or permanent solution to the transportation of production to the shore is receiving increasing attention from operators in the North Sea.

Offshore loading of oil as such is well known to the Industry, however, sufficient experience from hostile environments like the North Sea hardly exists.

The few systems operating in the North Sea must be regarded as prototype and the next generation of offshore loading units now being developed will be able to incorporate a number of the valuable lessons learned. Reliability and efficiency are key words in selection of the most suitable system and this paper will focus on a number of engineering aspects of importance in this context.

Figures and tables are purposely made in a schematic and general format to indicate the tendency rather than actual measured or calculated values.

Articulated buoyant towers without storage capacity and large volume floating anchored storage vessels will be the main types of offshore loading systems discussed in this paper as there appears to be a tendency in the industry towards these types of concepts.

A number of refined concepts utilizing one shuttle and one storage tanker whereby the latter is remotely connected to the buoy in different ways, articulated towers with two universal joints, one semisubmersible, etc., are proposed or even in use, but will not be subject to detailed comments here, as this is regarded as being outside the scope of this paper.

Concepts

The general concept which has proven successful for offshore loading is the single point mooring (SPM) idea. The tanker is moored with bowlines to a single point only, allowing the vessel to rotate freely (weathervane) around the buoy.

The different developments may be divided into two main groups on the basis of the type of fixation used; CALM and SALM (see fig. 1).

The catenary anchor leg mooring buoys (CALM) are the most commonly used offshore loading system. The simplest and most widely used being the single buoy mooring buoy (SBM).
Underwater Non-Destructive Testing
Authors: Lafferty Cyril F. , Watt Ian
Published: December 2007

Underwater Non-Destructive Testing is a highly complex and emotive subject about which many thousands of words have been written by eminent and extremely knowledgable people. Apart from touching on a few of the fundamentals as a way of introduction, it is not the intention of this paper to enter into the continuing discussion on the philosophy and reasoning behind, or implications of, NDT on underwater structures per se. Rather, its purpose is to relate how one particular company, Vickers Oceanics Limited, set about tailoring an NDT system around a diver lockout submersible in order to utilize certain advantages that this vehicle has over other alternatives at present in use in the North Sea.

In short, the article will not be presented from the platform of an NDT inspector, it will represent the viewpoint of an engineer, whose task was to produce a system to meet a market requirement, based on his experience with the underwater environment and his knowledge of the problems, both mental and physical, of the working diver.

Introduction

In the very early life of a platform there is the need to carry out overall regular inspections. This is to allow the owner to obtain sufficient information and data to build up the story of any progressive deterioration of his structure. The most generally accepted level of inspection at this stage, would simply be detailed video and high resolution photography, combined with measurements of cathodic protection levels and material thickness.

As experience and records show the necessity, the level of information obtained may have to be altered. With age the structure may have to be examined in more detail to discover stress or damage areas not immediately apparent in visual or video inspection, therefore more sophisticated NDT procedures would have to be applied.

At present the most efficient, and very often only, method of applying the more sophisticated NDT sensors to an underwater structure, is manually by a diver. The alternative being unmanned or conventional manned submersibles including JIM type suits, where access and/or manipulative dexterity may prove to be insoluble problems.
Fiscal Reliefs For The Exploration Of Marginal Oil Fields In The North Sea
Authors: Kemp Alexander George , Crichton David
Published: December 2007

The impact of the oil taxation packages introduced by tile U.K. and Norwegian Governments in 1975 on the exploitation of marginal fields is examined in this paper. The effect on the viability of operations depends on several factors such as the timing of the development of a field, future oil price and exploitation costs, and in the case of the U.K. whether the new field forms part of a multi-field development. Various fiscal incentives for encouraging development are examined. All of them are considered in the context of the existing fiscal framework and involve no radical alterations to the tax structures.

INTRODUCTION.

In both the U.K. and Norwegian sectors of the North Sea there is currently in existence a number of oil and gas fields which are regarded as marginal by the operators. Development decisions have still to be finalised in several cases. A marginal field cannot be defined by an academic observer or indeed by a civil servant drawing up tax schedules. It can be defined only by the exploiting company as it reflects the minimum return acceptable to the operator. It is also quite likely that different operators will demand different minimum rates of return which further complicates the definition. The situation is further complicated by the fact that oil exploitation takes place under conditions of uncertainty and the returns are really only expected ones when the key decisions are made.

Despite these problems Governments have set themselves the task of taxing oil exploitation with a view to taking for the state a share of the expected profits. There must therefore be a danger that actual tax packages will produce adverse consequences. So far as marginal fields are concerned there are two main general possible effects. The first is that the tax burden is so high that it leaves the expected post-tax return below the minimum acceptable by the operator and the field is not developed at all. The second is that later in the life of a field the tax burden is such that the field is prematurely abandoned. (This effect could of course be present in non-marginal fields as well). A tax system might produce other allocative effects. Thus, depending on the type of taxes the rate of depletion of a reservoir could be accelerated or decreased. The capital intensity of the technique of exploitation could be altered by the tax provisions and this could in turn change the rate of extraction.
Stabilized Foamed Acid, A New Stimulation Technique For Carbonate Gas Reservoirs
Authors: Briscoe Harold R.
Published: December 2007

Fracture acidizing of deeper Delaware Basin gas producing carbonate rocks, employs a number of techniques and acid formulations. A recently developed technique makes use of a stabilized foamed acid to achieve increased stimulation along with fast clean up. The quick recovery of treating fluids results in early stabilized flow permitting accurate testing and early gas sales.

Deeper gas zones with abnormally low bottom-hole pressures present a special problem when acid fracturing. New replacement wells and new wells drilled in older producing reservoirs, such as those in the deep Gomez Ellenberger Field, encounter partially depleted pressure conditions. Conventional fracture acidizing requires extensive, costly jetting with nitrogen and coil tubing to remove treating fluids and 'kick off' the well. Foamed acid stimulation treatments have not required jetting to initiate gas production.

Once acid in a stable foamed conditions gets into the created fracture it provides reduced leak off and reduced acid reaction rate with the soluble carbonate formation. This allows greater fracture penetration along with increased fracture conductivity throughout the fracture length. Adequate injection rates are possible, even with the reduced hydrostatic pressure of the foam column because of the low friction properties and reduced frac gradients in these reservoirs.

A number of foamed acid stimulation treatments in carbonate formations are detailed along with tabulation of production increases.

Introduction

The stimulation of deep carbonate reservoirs is greatly affected by acid spending times and fluid leakoff rates. To achieve adequate stimulation, a deep penetrating fracture with high conductivity must be created. Abnormally low bottom-hole pressure conditions, relative to depth, present a special problem for the return of stimulation fluids.

Foamed acid provides a new approach to reducing acid reaction rates with highly soluble carbonate rocks, along with achieving control of acid leakoff into existing hairline fractures. A great deal of energy, in the form of nitrogen gas, is induced into the reservoir to aid in the return of fluids to the well bore. A foamed flush fluid will greatly reduce the hydrostatic pressure of the fluid column in the tubing. Wells under these conditions will 'kick off' and flow, where otherwise they would not.

Fracture Aciding with Foamed Acid

The deeper gas zones with abnormally low bottom-hole pressures present a special problem when fracture acidizing. Fracture acidizing with conventional fluids requires jetting with coil tubing and nitrogen to remove treating fluids and 'kick off' the well. This involves a great deal of time and money. The evaluation of the well is delayed due to long cleanup time. Gas sales and subsequent revenues are delayed. If the rig is still on the well, costs are increased even more.
Considerations Relative To The Selection Of Sub-Surface Safety Valves A Guide To The Options
Authors: Dines C.A. , Calhoun M.B.
Published: December 2007

This paper attempts to outline the principal criteria relevant to the selection of a surface controlled subsurface valve for a known application. Since the sub-surface safety valve is arguably the most important element of any completion, careful consideration should be given to its selection: this is especially true of an offshore installation since the safety the effective performance of this valve. The considerations and parameters discussed in this paper cover valve type and design options whilst keeping paper cover valve type and design options whilst keeping in mind constraints imposed by well conditions, production requirements and safety philosophies.

Introduction

The primary function of the downhole safety valve in a well is to contain that well in a safe condition in the event of a catastrophe, any other attributes must be considered as secondary. This philosophy must be rigorously applied not only to the selection of the valve itself, but also to ancillary items such as locking mandrels, landing nipples, service tools, control lines etc. Virtually all of the offshore operators and regulatory bodies around the world today specify the use of hydraulically actuated, surface-controlled sub-surface safety valves (SSSV) which in most cases interface with the platforms emergency shutdown system-the scope of this paper will therefore be confined to such surface controlled valves and furthermore is limited to discussion of valves which are currently in common use.
Use Of Clear Brine Completion Fluids As Drill-In Fluids
Authors: Conners James H.
Published: December 2007

Clear brine completion fluids have been used successfully as "drill-in" fluids in recently drilled California wells. Brine fluid or saltwater drilling is not an uncommon practice, however, brine water is primarily used, when practice, however, brine water is primarily used, when actual drilling muds are not required, because of its economic advantage over muds.

Distinct differences exist between saltwater drilling and the brine fluids implemented in California. These wells used calcium chloride/calcium bromide clear brines with densities in the 1.62 to 1.63 kg/dm 3 (13.5 to 13.6 lb/gal) range. The object of using the brine fluid was to enhance production rates by minimizing formation or "skin" damage, production rates by minimizing formation or "skin" damage, which in turn greatly offset the initially higher cost (in comparison to conventional drilling muds). The brine is called in drill-in fluid in these cases because conventional muds were used to drill the wells prior to reaching the production zones.

Casing was set, muds were displaced by the calcium chloride/calcium bromide brine, and the production zones were drilled. The production zone, the Stephens formation, is an extremely low-permeability, 9.9 × 10(-6) to 4.9 × 10(-4) m2 (.1 to .5 millidarcy), arkosic sandstone. The brine fluid was selected because formation plugging in previous wells had been attributed to conventional mud systems, resulting in less than anticipated production rates.

The application of these brines necessitates careful consideration of formation type, expected formation pressure, and bottom-hole temperature. Drilling with pressure, and bottom-hole temperature. Drilling with the brines requires modifications of drilling practices such as fluid system hydraulics, surface circulating system design, and drilled solids removal equipment. Preliminary data from in-progress product evaluation Preliminary data from in-progress product evaluation of these wells appear favorable.

Introduction

The Cal Canal Field is located approximately 35 miles west of Bakersfield, CA. It was discovered in September 1977 by Oxy Petroleum, Inc., in partnership with Chevron U.S.A., Inc., with the drilling of well Cal Canal No. 1. The well was drilled to a total depth of 3604 m (11,325 ft) and was completed flowing initially 5.4 × 10(4) m3 (1.9 MMcf) of gas per day plus 79 m3 (500 bbl) of condensate per day from Stevens Sands, silt points, and shales at approximately 3505 m (11,500 ft). Successive wells were drilled on a 16-ha (40-acre) spacing: 15 more by Oxy and 4 by Getty Oil Co., bringing the total to 20 wells (including one dry hole). Normal drilling and completion time was 70 to 80 days at a cost of approximately $1.8 million.

The Stevens' most productive section was about 213 m (700 ft) thick and was made up of sands, very dirty sands, siltstones and shales. Net pay at Cal Canal was extremely difficult to determine from well logs.
The Prospects Of Natural Gas Supplies And Markets In Europe And Their Influence On The U.S.
Authors: D'Andrea Lucio
Published: December 2007

The reason for presenting this paper to the Society of Petroleum Engineers is the realization that little coverage is given in the U.S. to natural gas developments in Europe. Perhaps this is due to the concern that both Europe and the U.S. share with regard to oil. Both depend on external sources of oil supplies significantly, even more so Europe than the U.S. It may also be due to the fact that in recent years we in the U.S. have been concerned with solving our own natural gas problems, which our European friends observed with interest, but were somewhat bewildered by our inability to arrive at a satisfactory solution.

I do not think that gas developments in Europe deserve to be ignored, if we recognize the common goal which we share with Europe of utilizing alternative energy sources in order to reduce the heavy dependency on imported oil.
World Energy: Trends And Outlooks
Authors: Hedland C.J.
Published: December 2007

Before addressing the subject of "Issues for the 80's," it might be a good idea to look back for a moment at the events of the 70's. The decade just ending has transformed the economics of energy, of course, and greatly increased its political sensitivity. Before 1970, energy supply was something most people more or less took for granted. Like the flow of oil through a pipeline, the system worked smoothly and unobtrusively and gave little reason for public concern. Today, energy supply is a major issue in almost every nation of the world; it can be argued that energy has been the central public issue of the decade. No one could have foreseen the full extent of these changes. The oil-exporting nations' assertion of control over their oil resources, the escalation of world oil prices, the rising concern about the environment, the expansion of government regulation into the energy business, the political crises in the Middle East which precipitated the oil shortages of 1974 and 1979 — all these precipitated the oil shortages of 1974 and 1979 — all these developments took us by surprise to some degree because they were sharp breaks with the past. If the details were unpredictable, however, the outlines of the coming world energy problem were already visible in the late 1960's. World energy consumption was already pressing hard on energy supply, and the industrial nations were becoming increasingly dependent on imported oil. As the 1970's have progressed, it has become more and more clear that this is the root of the problem: A fundamental imbalance in energy supply and demand, and an excessive dependence on a single source of energy - oil.
Hard Decisions: A Perspective On Free World Energy Realities
Authors: Swearingen John E.
Published: December 2007

Swearingen, John E.* Chairman of the Board, Standard Oil Company(Indiana)

Good afternoon. It is always a pleasure to visit Las Vegas, and it gives me very special pleasure to address the Society of Petroleum Engineers. Petroleum Engineers. As you know, much of the time of oil company executives these days is taken up with dealing with that huge assortment of non-oilmen in Washington who are attempting to run our industry. It is, therefore, refreshing to meet with a group of professional people who know what they are doing and how to do it I wish the people who know what they are doing and how to do it I wish the same degree of competence pertained within the federal bureaucracy.

As matters now stand, so many people and departments wield influence on energy policy that it is extremely difficult — and sometimes impossible — to develop long range plans. And without knowing the rules of the game, we cannot realistically make those hard decisions which I have been asked to discuss today.
Evaluation of CO2 Based Vapex Process for the Recovery of Bitumen from Tar Sand Reservoirs
Authors: Khelifa Talbi , Maini Brij B.
Published: December 2007

The vapour extraction (Vapex) process has recently gained considerable attention for its promising application for the recovery of heavy oil and bitumen reservoirs that are deemed unsuitable for thermal methods. In conventional Vapex process, a mixture of vaporized solvent (propane and/or butane) and a commercially available non-condensable gas (methane, natural gas) is injected into the reservoir to reduce the oil viscosity. Therefore, the cost of these injected gases per barrel of produced oil is critical for the economic viability of the process. With predicted increase in the gas prices, the process has lost some of its initial attraction.

For reducing the solvent cost, the injection of CO2 as a non-condensable gas appears to be an attractive alternative. The advantage of this low cost alternative is that the solubility of CO2 in heavy oils is significantly higher than that of methane. Consequently, the mixture of propane and CO2 can provide greater reduction in oil viscosity compared to the equivalent mixture of propane and methane. In addition, this CO2 injection can play a significant role in sequestering CO2 emissions. However, the CO2-propane-heavy oil system shows complex phase behaviour, forming multiple liquid phases. Such multiple liquid phases can reduce the effectiveness of gravity drainage process by introducing complex relative permeability effects.

This paper presents an experimental study aimed at developing a new CO2 based Vapex process for in situ recovery of bitumen from tar sand reservoirs. The experiments have been performed in a partially scaled physical model at different operating conditions. The main conclusion from this study is that the CO2 based Vapex process is more cost effective and environmentally friendly than the conventional Vapex process.
Extended Brigham Model for Residual oil Saturation Measurement by Partitioning Tracer Tests
Authors: Tang Joseph S.
Published: December 2007

Brigham’s model has been used extensively in the petroleum industry for the design and interpretation of interwell tracer tests. The model is based on correlation and has included physical dispersion as an input parameter. In spite of its limitations, the model is useful in estimating layer heterogeneity, layer distribution, permeability contrast and dispersion in the reservoir. However, the model can only handle non-partitioning tracers that have no solubility in oil. With the advancement in partitioning tracer technology and interpretation technique, interwell partitioning tracer test has gained its popularity, especially in China, for determining residual oil saturation Sorw between wells. Partitioning tracer test also finds its application in environmental protection, where the test is routinely run to determine the amount of non-aqueous liquid phase NAPL trapped underground due to spill or seepage. While sophisticated streamline or finite difference simulators have been increasingly used to determine Sorw distribution from the tracer production data, simple semi-quantitative model still has its merits in providing a direct, unambiguous estimate of average Sorw along the tracer flow path. This paper broadens the scope of the original Brigham’s model by incorporating partitioning tracers into the model using a chromatographic transformation technique. By matching the partitioning and non-partitioning tracer curves, Sorw can be determined by layers. The extended Brigham model was applied to the Ranger oil field multiple tracer test and the residual oil saturation determined compared favorably with those obtained by chromatographic transformation method and numerical simulation.
The Effect of Treating Agents on the Electro-Chemical Activities of Drilling Mud Filtrates
Authors: Lipson Leonard B. , Overton Harold L.
Published: December 2007

The formation water resistivity is presently calculated from electric log data with the assumption that both the waters in the drilling mud and the formation are essentially sodium chloride solutions. This is found to be in error with most of the drilling muds in use today. This paper treats the effect of mud chemicals on formation water resistivity when SP data is used for the water resistivity calculation.

The Nernst equation for activities of ionic solutions, that are essentially univalent, is used to evaluate the spontaneous potential. This equation is:

(Equation)

Eq. 1 has both a shale membrane and a liquid junction component. Only the shale membrane component was investigated in this study, since it is usually the most significant parameter. It may be expressed as:

(Equation)

Since the activity of the mud filtrates must be known for given resistivities, both of these parameters were measured in this investigation. The results showed that several properties which are being measured at the well head can be used to find the activity of a mud filtrate if the resistivity is known. The activity of mud filtrates rarely varies with the sodium chloride in solution alone. Important properties causing activity changes are filtrate alkalinity and calcium content. Graphical representations are prepared showing the correlation with each of these parameters.

Introduction

C. and M. Schlumberger and E. G. Leonardon in 1934 considered the self potential curve of electrical logging to be composed of the combination of a streaming potential and a boundary potential. They believed that the boundary potential was set up at the face of impermeable material, such as clay or shale, due to the interaction of fluids containing different salt concentrations. The electro-chemical component of the self potential curve was given as

(Equation)

where K is an unknown constant, Rm is the mud resistivity, and Rw is the connate water resistivity.
Exceeding Drilling Performance and Environmental Requirements with Potassium Silicate Based Drilling Fluid
Authors: Duncan Jayne , McDonald Michael
Published: December 2007

Since the re-introduction of silicate based drilling fluids, the vast majority of wells have been formulated around sodium silicate. Somewhat surprising, it is only recently that potassium silicate has become the alkali silicate of choice for use on-land. Described are the chemistry, drilling and environmental performance of potassium silicate. Field results are presented for a series of wells drilled in British Columbia, Canada using a potassium silicate based drilling fluid. These results show that drilling objectives were exceeded and further demonstrated ease of disposal with minimum impact on the environment.
Methods for Calculating Profitabilities
Authors: Brons F. , McGarry M.W.
Published: December 2007

To rank a variety of ventures in the order of their profitability, a yardstick is needed in which both the profit and the time at which this profit is realized are included. This paper describes methods for evaluating two of the more common yardsticks, i.e., the present day value or the total profit for a fixed interest rate and the internal rate of return. No attempt is made to present arguments in favor of either of these criteria. Based on a number of simplifying assumption, tables and graphs have been prepared with the aid of which the profitability of single incomes, constant incomes, and three types of declining incomes can be calculated for a wide range or interest rates. Two examples are given to explain the use of the graphs and tables.

Introduction

The total profit of a venture is by definition the difference between the total net income and the capital investment. Where, as is usually the case, the investor has a choice of ventures in which he can invest his money, he will need a single yardstick to rank these ventures according to their profitability. It is at once obvious that the total profit cannot always be a sufficient criterion: a smaller profit returned to its investor after a short time may be more desirable than a larger one, for which the investor has to wait a long time. A yardstick by which ventures can be ranked uniquely according to their degree or profitability must therefore incorporate the monetary value of the profits and the time at which they are returned to the investor.

Several yardsticks are being used in the oil industry which more or less approach this criterion. In the present paper only two will be considered:

the present day value (or deferred value) or the total profit, and

the internal rate of return ["yield", "earning power", "rate of return," etc.]
Optimization of a 3D Seismic Survey Onshore Abu Dhabi – From Field Tests to Final Design
Authors: Al Jeelani Abu Baker , Marmash Samer , Bin Ishaq Abdul Salam , Al-Shaikh Ahmed , Kleiss Erik , Al Shamsi Ali , Haggag Ismail , Marsden Paul
Published: December 2007

Reservoir heterogeneties play important roles in reservoir description processes. It is therefore imperative to understand the source of uncertainties influencing structural and stratigraphic interpretations of reservoirs.

An integrated reservoir, and seismic modeling study over an onshore giant field in Abu Dhabi came to the conclusion that 3D seismic is the most efficient approach to detect the reservoir heterogeneiy and structural uncertainties that are thought to be responsible for the irregular fluid flood front advance and consequently for the reservoir management problems.

In preparation for a large vibroseis 3D seismic survey over the subject field, 2D and 3D field tests were carried out to determine optimum source energy distribution. Several versions of the 2D and 3D data were acquired with different source geometries and processed up to stack, migration and inversion (for 3D). The 2D test showed that in this area final data quality does not depend on vibroseis sweep length (i.e. source energy). A subsequent 3D test showed that final data quality is marginally dependent on dense source arrays, but is enhanced considerably using a finer areal distribution of source points. This could be used to improve the data quality and at the same time to reduce the cost of the subsequent production 3D survey.
Completion Practices for Prudhoe Bay Wells
Authors: Knepler J. R.
Published: December 2007

The purpose of this paper is to present an overview of the current completion practices for wells in the Eastern Operating Area of the Prudhoe Bay Field. ARCO Oil and Gas Company is the operator of the Eastern half of the Prudhoe Bay Field and SOHIO Petroleum Company operates the Western half. Completion practices in general are similar in both operating aroas; however, there are a few significant differences. This paper refers to practices in the ARCO Oil and Gas Company operating area only.

With only two and one-half years of production behind us, there is relatively little history on Prudhoe Bay wells, but we have produced a billion barrels of oil in that short time. The operators have drawn on what is believed to be the best available practices in the industry in developing their operating plans for Prudhoe. There is no universally right way to complete all wells, and we believe we are doing what is best for our situation. In this paper we hope to present the perspective of how and why wells are completed the way they are at Prudhoe Bay.

The primary consideration in every completion design is the prudent maintenance of the safety and integrity of the well throughout its life. In addition, all completions are designed to accomplish two basic things: 1. To minimize formation damage or maximize well productivity; 2. To provide maximum flexibility over the life of the well. It is through diligent adherence to these goals that the optimum economic benefit is realized from each completed well. This paper describes the basic completion practices utilized at Prudhoe Bay to achieve these goals.
Reservoir Stimulation of Dirty Sandstones
Authors: Davies David K.
Published: December 2007

Approximately 80 percent of the world's sandstones can be classified as "dirty".1 However, dirty sandstones contain only 15 percent of the world's oilfields.2 Most oilfields have been discovered in clean sandstones. Differences in success ratios between clean and dirty sandstones suggest either that: 1. dirty sandstones do not contain recoverable hydrocarbons (particularly oil), or 2. hydrocarbons are more difficult to extract from dirty sandstones than clean sandstones. Commercial quantities of hydrocarbons have been discovered in dirty sandstones.3 This strongly suggests that their hydrocarbon potential is good. However, detailed studies of the composition of dirty sandstones indicate that they are highly susceptible to formation damage during both drilling and stimulation. Care and attention to rock mineralogy and fluid composition can minimize or prevent formation damage in dirty sandstone reservoirs. With properly designed stimulation procedures, 80 percent of the world's sandstones (the dirty sandstones) become highly prospective and good exploration targets.

The terms "clean" and "dirty" sandstones are used (and often misused) widely in the petroleum industry. Clean sandstones are comprised dominantly of sand grains which are chemically stable and physically durable. On the other hand, dirty sandstones are comprised dominantly of sand grains which are chemically unstable and physically non-durable (Figs. 1 and 2). Note that the terms clean and dirty do not involve the amount of clay or shale in the sands. Both clean and dirty sands can be clay-rich or shaly. Distinction between clean and dirty sands is thus based on the composition of the sand sized particles, not the relative abundance of clay or shale.

Reservoir stimulation in dirty sandstones has, as its principal aim, the enhancement of rock permeability. In order to predict the effects of specific stimulation efforts, it is necessary to first understand the reasons for low permeabilities and porosities in many dirty sandstones. Specific stimulation efforts should be designed to attack either the principal cause of porosity-permeability reduction, or those causes which can be treated with the present state of the art.
The Use of Floating Production Systems To Evaluate Marginal Reservoirs
Authors: Caycedo Luis , Seay F. T.
Published: December 2007

There are marginal oilfield discoveries in Indonesia which cannot justify installation of fixed production platforms but can still be economically developed. The solution to these marginal oilfields is the utilization of unique Floating Production Systems (FPS). The FPS is becoming more accepted as off-shore construction costs continue to increase and these relatively low-cost production facilities are proving to the most economical method of production in marginal fields such as encountered off the coast of Indonesia. These FPS's are self-contained, complete with modern accomodation for production personnel and are equipped with the latest in production systems.

Such floating production systems are currently operational in the Aijuna "MM", "FF" and "F" fields, Java Sea, for Atlantic Richfield Indonesia and they are proving to be attractive in determining reservoir behaviour, probable reserves and are proving to be ideal in minimizing initial capital expenditures required for permanent production platforms.

This paper is intended to describe the economics of the unique Floating Production Systems and to also discuss the selection of equipment and operational experience.
Udang Field: A New Indonesian Development
Authors: Mattes Earl M.
Published: December 2007

The Udang Field is located in the Natuna Sea, approximately 1,000 kilometers North of Jakarta. The discovery well was drilled in 1974. Field commenced production 18 January 1979. It now has 10 wells producing about 25,000 BOPD. A total of thirteen wells have been drilled.

Facilities installed consist of a 4,500-ton drilling and production platform supported on eight piles driven 320 feet into the ocean floor. The platform, the biggest in Indonesia, is connected by a 400-foot bridge to a flare tripod. Production facilities capable of processing 40,000 barrels per day of high pourpoint crude are installed on the platform. Processed crude is pumped through dual insulated pipelines to the Udang Natuna, a 93,000 deadweight-ton tanker which is permanently moored 6,100 feet from the platform by a single point mooring system. Export tankers breast moor alongside the Udang Natuna to receive finished crude.

A total of 24 months elapsed between commitment to the project and completed development.
Efficiency Of Offshore Production Via An SPM System
Authors: Warren J.
Published: December 2007

In recent years, offshore exploration efforts were extended into deeper and deeper water located further and further from shore in less and less hospitable enviomments. Consequently, not all of the fields discovered were feasible – economically and/or technologically – to develop and to produce using established methods. To improve this situation, a transportation system was developed which allowed crude-oil tankers to be loaded via a single-point mooring buoy, SPM, located near a producing platform – thus, the need for expensive, deep-water pipelines was reduced.

Despite this innovation plus additional improvements, many discovered fields still remain in the marginal category for conventional evaluation. Therefore, it is necessary to optimize the total production/storage/transport system before consistently rational decisions can be made regarding field development.

This paper presents a method for predicting the behavior of an SPM system – considering the effects of tanker size, number of tankers, deviations from schedule, weather, loading rate, storage capacity and production rate( The primary descriptive factor determined by this approach is the operating efficiency of the storage/transport system which constitutes a constraint on the production system. Since the production system can be optimized on an economic basis while recognizing well productivity and reservoir performance, it is possible to specify the optimal configuration for the entire system – and to assure the compatibility of the upstream and downstream elements.

The analysis of the SPM system, a procedure for optimizing the production system and a discussion of the upstream-downstream coupling – and its effect on the optimization of the entire system – are presented in this paper. A simple, but complete, example is also included.
Diagnosis of Bacterial Sulfide Problems in Secondary Recovery and Salt Water Disposal Water Injection Systems
Authors: Moore Burton H.
Published: December 2007

Expense of bactericide treatment in injection water can be a major item in the operation of a waterflood or disposal system. Each operator of such a system desires to know whether such expense is necessary and which bactericidal chemical is most economical for his system. The diagnosis to be described makes use of modifications in recognized analytical methods for on-the-spot determinations of total sulfide and of populations of "sulfate-reducing bacteria". Activity of the bacteria is judged on the basis of increases in sulfide concentrations and/or in increases in bacterial populations as the water progresses through the system under study.

The methods used in this diagnosis are of sufficient sensitivity that indications of bacterial activity should be apparent if down-hold bacterial sulfide formation is a significant factor in any water injection system. If the diagnosis fails to show a definite bacterial problem, more careful study of other factors is indicated.

Descriptions will be made to cover typical evidence for:Uncomplicated appearance of bacterial sulfide in injection water accompanied by increasing numbers of sulfate-reducing bacteria or accompanied by high bacterial populations.Localized pockets of bacterial sulfide formation. Water passing such pockets would pick up sulfide and bacteria either continuously or in "slugs".Cases where one or more supply waters contain dissolved sulfide with or without significant numbers of sulfate-reducing bacteria. Little or no additional sulfide is formed by the bacteria but the soluble sulfide reacts with iron salts, metallic iron etc., to produce "black water". Treatment with chemicals having properties other than or in addition to bactericidal activity is required.Complications associated with imperfect mixing of widely differing supply waters.

Concentrations of sulfide and bacteria passing sample points fluctuate, hence diagnosis is possible only by alterations in the operation of the system.
A Comparison of Caustic Soda and Soda Ash as Chemical Media for SO2 Recovery in Oilfield Steam Generators
Authors: Siemak John B. , Reyes Ricardo B.
Published: December 2007

Caustic soda and soda ash were used as an alkalinity source in the liquid scrubbing of SO2 in flue gases produced from crude oil-fired steam generators used in thermally-enhanced oil recovery. It was found that caustic was utilized more efficiently, thereby allowing the SO2 scrubber to run at a lower pH with a higher SO2 removal capacity. Also, overall economics favored the use of caustic over soda ash in this scrubbing application.
Silverdale Combination Thermal Drive Project
Authors: Cady G. V. , Hoffman S. J. , Scarborough R. M.
Published: December 2007

In eastern Alberta, the Lloydminster Field extends from Township 48 north to Township 51 and west from the Alberta border to Range 3. A total area of more than 120,000 acres under which pools of heavy oil vital to our world energy needs, remain well saturated after years of production by conventional methods. General Crude Oil Company has acquired interest in the Sparky Q pool in the Lloydminster Field four miles south of the town of Lloydminster, Alberta. In 1975, General Crude Oil initiated a combination thermal drive project in an effect to increase the pool's recovery from 226,400 barrels to 6,854,000 barrels. This would be an increase in oil recovery from 1.2% to 37.1% of the original oil in place.

The proposed project's requirements were to drill 33 development wells, install flowline and surface facilities, and operate the combination thermal project for sixteen years. The wells were drilled and completed by December, 1975, along with the networks of flowlines, circulating water lines and electrical cables that were buried from the individual well-head to a central tank battery. The field was placed on production in early 1976 and produced by primary means until March, 1977. General Crude ignited four 30 acre inverted seven-spot patterns with a gas igniter. Air was injected down the four injection wells from an Ingersoll-Rand 4 RDS balanced opposed four stage compressor. Through 1978, five more patterns were ignited to bring the burn area to 270 acres; which contains some 4,000 acre feet of oil and sand and 8 million barrels of oil.

General Crude Oil engineers have worked since the 1977 ignition to produce 336,000 barrels of oil after injecting 1,200,000,000 cubic feet of air and 149,781 barrels of water in the combination thermal drive combustion process, They are recovering 84% of the injected gas and sustaining a 3.5 MSCF/Bbl air injected oil produced ratio. Optimistically, these factors point to a successful project, based on General Crude's past ten year experience with the combustion process.