bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling Foams for Acid Diversion
Authors: Rossen W. R. , Wang M.-W.
Published: December 2007

Successful foam diversion in matrix acid treatments depends on foam mobility during foam injection and liquid (acid) mobility after foam injection. We present new coreflood data for both flow regimes. At fixed quality and high flow rates, we find that foam behaves as a shear-thinning fluid with power-law exponent of about 0.6. For qualities below about 80%, when gas and liquid flow rates are varied separately, pressure gradient is nearly independent of water flow rate, as reported by Osterloh and Jante (1992) for foam below a threshold foam quality. Upon liquid injection after foam, pressure gradient falls to a steady-state value that varies little with liquid flow rate. The transition to this steady-state pressure gradient is strongly affected by gas expansion as pressure falls, which makes extrapolation from laboratory coreflood to field application tricky. However, although some gas escapes during this transition period, the foam front does not advance; that is, this escaping gas moves as free gas, not foam. These findings are intermediate between the simple quasi-Newtonian model of Zhou and Rossen (1994) and the extremely shear-thinning behavior reported by Parlar et al. (1995) and Robert and Mack (1995).

A simple new model accounts for many of the trends observed. This model assumes that foam mobility is controlled, not by foam coalescence and capillary pressure as for high-quality foams, but by trapping and mobilization of foam bubbles of fixed size. This model explains how foam mobility can be independent of liquid flow rate; why steady-state pressure gradient falls moderately during liquid injection following foam; and why this pressure gradient is relatively insensitive to liquid flow rate. Implications of the model for design of foam processes are discussed.
Evolution of Control Systems Associated with the Management of Electrical Net in a Distribution Company
Authors: Minio E.E. , Rovira J.M. , Colombo D.H.
Published: December 2007

This document summarizes the evolution towards the new technologies of the Control Systems within the restructurization process of a private Electric Energy Distribution Company. In the first part of the document, the control systems that the company had at the time of its privatization are described.

Following is the implementation strategy that joins technology, operatives, and organization.

Then, the architecture and organization of the Telecontrol System implemented is detailed (with a horizon of 15 years). This system serves the purpose of telesupervising and teleoperating the Transmission, subtransmission and distribution networks in the optimal technical economic conditions.

Finally, it is concluded with the future vision of the project.

Introduction

Within the Electric Energy Distribution business, one of the keys is the control of the electric process from the interconnection points, where energy is exchanged up to the point of supply to the clients.

Under this process, the objective searched for by Edenor for the control of its electrical process is Telesupervision and Telecontrol of the transmission, subtransmission and distribution networks In optimal quality and security conditions, with minimal losses, operative costs, and penalties.

Give solution to the whole acting environment of the Control Center: Operation Preparation, the Operation and the Analysis of the Exploitation Results; its integration with all the distribution systems: Complaint Center Service Quality, Network Planning, Enery Service, Client Service, Maintenance, and Energetic Balance.

2.- Situation at the beginning of service

In September 1992 and within the privatization process initiated in the electric sector of the Greater Buenos Aires, Edenor was born as one of the private Distributors.

2.1.- Installations

Edenor's electric network was (or is, being that some of the data is current) composed of:–High tension Transmission and Subtransmission Networks (levels of 220 kV, 132 kV, and 27.5 kV. Aerial lines cover 651 km and underground lines cover 492 km).–Medium tension Distribution Network (13.2 kV and 33kV. Aerial lines: 3,201 km; Underground lines: 2,954 km).–Low tension distribution network (levels of 380/220 V. Aerial lines: 20,699 km; underground lines: 3,652km).–Substations high tension and high/medium tension (56)–Medium tension Centers (18)–Medium/low tension Transformation Centers (9357)–Clients: 2,100,000
Legal Framework for the Enviroment Required from a Distribution Company in the Privatization Process
Authors: Rovira José María , Márquez Julio A. , Mazzei Humberto R.
Published: December 2007

Different organizations are showing more preoccupation for acheiving a greater performance in the protection of the environment. This growing worry has as an envolving frame a series of environmental pressures that are added to the already existing worries in the companies. It's worth noting that national and international legislation is getting stricter, the public opinion is exercising a much more severe role, consumer requirements are growing considerably in order to improve the quality of their lives, and the development must be completed within a circle of restrictive economic measures.

As a consequence of this, many companies have started to take actions, such as: environment audits, environment impact studies, etc. But these studies do not insure, within themselves, a good organization performance, they simply show us a situation regarding the follow-up of current policies, besides showing us the positioning of the company in order to meet all of the future reglementary measures. Our country has also started its part in conserving the environment on an energetic level, creating organizations at the highest government levels in order to control said policies and taking advantage of the privatization wave, establishing environmental obligations for the companies, through the regulation of their activities.

In the case of Edenor, which grants services of distribution and commercialization of electric energy, according to its Concession Agreement, it must: adequate its actions with the objective of preserving and/or improving the ecosystems involved in the development of its activity, fulfilling the policies currently in force, as well as those established in the future, destined to the protection of the environment, approved by Resolution N° 170/92 of the National Energy Department. With regards to this, we will proceed to show a brief analysis of the environmental policies in force on a national, provincial and municipal level, which directly or indirectly regulates the protection of the environment in general and, particularly, natural resources.
Investment Decisions Under Uncertainty Conditions
Authors: De Lellis V. , Ferro H.
Published: December 2007

The main objective of the current analysis is related to the need everyday found in the Sector, and essentially in the electrical sector, to have at hand a methodology allowing us to decide upon the convenience to perform or not an Investment, to delay or not such a decision, and mainly about the possibility of establishing the degree of uncertainly contained in each of the explanatory variables (prices, demand, rates, etc.), allowing to reach the maximum profits with the least Riski.

There are two levels of problems to solve. The first on refers to the decision of establishing the opportunity for an investment, and the second, is the conceptual and highly conflictive problem posed by the need to differentiate the classical technical-economical analysis based on the marginalist theory from the managing aspect of the financial investment which, in its search of maximum performance (profit), is not necessarily reached through the marginalist theory.

Current experience in Califomia-Oregon (COB) and Palo Verde, the Scandinavian countries, New Zealand, and Cammesa, permits to suggest the convenience to implement an auction system allowing to bring face to face both the offering parties (producers) and the demand parties (distributors, major users, etc). They should confront the contingency and, not necessarily, should they be guided by the economical optimums, thus reaching spot prices which could be under 20 US$/MWh.
Regional Energy Interconnection Gas Pipelines vs. Power Transmission Lines Comparison
Authors: Carranza Hugo Alberto
Published: December 2007

The countries of the Southern Cone of America are experiencing deep changes in their Energy area. The sustained growth in the demand of energy, in some cases at a yearly rate exceeding 7%, and the need of maintaining the long term cost of energy within competitive values, are moving the region to a higher energetic integration and to a diversification and optimisation of their resources.

Within this new transformation scheme, the existence of large natural gas regional reserves, plus the technological advances in thermoelectric generation, using combined cycles with natural gas, and with an efficiency near to 60%, offer clearly the lower cost long run marginal alternative for power generation. The great distance that exists between the gas fields and the consumer markets, the rates of growth and the concentration of the demand in certain areas, the need for the conversion of the electrical frequency amongst Brazil and the countries of the region, are subjects that have their influence and condition the decisions regarding investments in energy. In this context, the selection of the means for transporting the energy, by Natural Gas Pipelines (NGP) or Electrical Power Transmission Lines (EPTL) is starting to be an interesting subject of study for the specialists in energy.

The technical and economic comparisons performed between both transmission means allows us to arrive at some conclusions regarding the future range of application of each technology. This study submits the conclusions of the above mentioned comparison. It also shows the methodology used for its application to different situations than those assumed.
Gas Geopolitics in the Mercosur Countries
Authors: Barreiro Eduardo M.
Published: December 2007

Lic. Eduardo M. Barreiro

In a world context in which the economy tends to globalize; in which the oil prices are the same in any point of the planet, only depending on the API gravity and sulfur content, to speak of "Gas Geopolitics in the Mercosur Countries" seems redundant and old fashioned.

In the concept of "geopolitics" a local connotation is implicit, particular and different of the rest of the world; therefore opposed to the globalization concept.

But the globalization is not yet valid for the natural gas.

Its value is not the same in United States, in Europe or Japan. Neither the prices, nor its oscillations, nor the contracts, are equal; there are market differences. This is due to a fundamental motive: transportation. To transport gas is more expensive than to transport oil.

If transported by pipeline, same pipe diameter transfers only 1/5 of the implicit energy in the crude transportation. The needed investment in the gas pipeline construction is higher (pretreatment plants are more complex, safety procedures are strict, control systems much more expensive). The cost is much higher if the gas is carried by ship; LNG transports demand a previous liquefaction process, transportation in a special and dedicated ship, more expensive than an equivalent tonnage oil tanker, and the regasification at the arrival point.

The World Gas Market has been divided in three main geopolitical regions:Canada/United States/MexicoNorth Africa/Europe/C.I.S. RepublicsJapan and North Pacific Countries.

Up to now, South America and specially the Mercosur countries have been ignored as an emergent geopolitical new area, because its emerging gas market only recently started to be delineated.

But in spite of the fact that is new, possibilities are big. With potential markets which foreseeable characteristics are presented in this work, and providing countries that can supply gas reserves for those markets, Mercosur is appearing as a new geopolitical area to consider, and in a region for large investments in production, transportation, distribution and natural gas utilization.

Nevertheless, the development will not be as explosive as has been outlined by some authors; it will be slow. The bottle neck is not only the huge amount of money needed for the necessary investments, but the time that will take the accomplishment of the needed infrastructure works. The historical conversion process to gas use in Argentina, first gasified country of the region, will be analyzed, and the analogies and differences with the other countries are going to be outlined.

Gas reserves, that exist in the countries in several basins to cover the supply to other member countries, are going to be presented.

The necessary transportation infrastructure to send natural gas to other Mercosur markets will be summarized.

With this work I shall try to present a photograph of this new geopolitical area for the natural gas, to define it, and to incorporate it by own rights into the other geopolitical areas of the world.
Horizontal Well and Extended Reach Technologies with Reported Problem Areas and Operational Practice in North America and Europe
Authors: Crouse P. C. , Tada H. , Takeuchi T.
Published: December 2007

In 1994 and 1995, studies were initiated to investigate developments, activity, and philosophies of the larger oil and gas industry in implementing horizontal well and extended reach technologies. North American and European operators, contractors, service companies, government authorities, and educational institutions were 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. 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. This paper is essentially the same paper as IADC/SPE 350548 except certain sections were not included and sections added encompassing other areas investigated over the two years.
Gas Frac - A New Stimulation Technique Using Liquid Gases
Authors: Hurst R.E.
Published: December 2007

Gas Frac is a fracturing treatment using a new and absolutely water-free fluid system. The fluid is liquefied petroleum gas and liquid carbon dioxide mixed in such a ratio that they remain a liquid and behave as other liquids as long as they are under adequate pressure and below their critical temperature. After the fluid is heated to this temperature in the reservoir and pressure released, the liquid reverts to a gas. This results in extremely rapid clean-up and no residual fluids are left in the formation.

Gas Frac was developed especially for gas well stimulation. Results to date have proved the technique to be very successful.

This paper discusses the technique of Gas Frac and the materials and equipment used. analysis of results of treatments is presented.

Introduction

Many gas bearing reservoirs have resisted stimulation from conventional methods of liquid injection. Expected stimulation results often are totally or partially offset because of liquid retention by the reservoir. Core testing on many reservoir rocks, especially those with pore structures displaying a high surface area pore structures displaying a high surface area (pin point porosity), verifies this type of damage.

Frequently, liquid retention damage was credited to water sensitivity when water, brine, or acid was used as the treating fluid. It is recognized that water sensitivity is a real problem and frequently adds to the complications problem and frequently adds to the complications associated with liquid retention. When oils were used in gas reservoirs with negative results, the problem was related to the creation of a third phase.

Without becoming involved in the academic merits of classifying negative stimulation results according to the aforementioned problems, a new stimulation fluid has been created which can be useful in the prevention of liquid retention and/or water sensitivity. For these reasons, this new fluid will have widespread application in gas reservoirs and to a lesser degree will prove its value in many oil wells. The new stimulation fluid is one composed of liquefied petroleum gases and liquefied carbon dioxide in varying volumetric proportions such that the resultant liquefied gas can be used to perform hydraulic work, then allowed to perform hydraulic work, then allowed to volatilize at reservoir producing conditions.
Application of Coiled Tubing Drilling Technology on a Deep Underpressured Gas Reservoir
Authors: McGregor B. , Cox R. , Best J.
Published: December 2007

In November of 1996, Apache Canada drilled a gas well with coiled tubing in the Harmatten Field northwest of Calgary. A a true vertical depth of 2572 metres, the well was the deepest successful coiled tubing horizontal well in Canada to date. The reservoir was underpressured with a pressure gradient of 6.5 kPa per metre. The well was drilled and cased to 90 degrees with conventional rotary drilling operations, after which a coiled tubing unit was rigged on and the horizontal section of the well drilled underbalanced. A total of 368 metres of underbalanced 120.7 mm wellbore was drilled, which included two open hole sidetracks. Gas production rates during drilling were in the range of 5-6 MMSCFD, and reservoir gas contained approximately 0.5% hydrogen sulfide.

This paper will describe the equipment and associated drilling performance for this operation, and will elaborate on open hole sidetracking capabilities. Drag modeling, tubing lockup, and potential lateral extent for drilling at these depths will also be assessed.
Advances in Sliding Sleeve Technology and Coiled Tubing Performance Enhance Multizone Completion of Abnormally Pressured Gulf of Mexico Horizontal Well
Authors: Plauche Ricky , Koshak W.E. Skip
Published: December 2007

Advances in sliding sleeve technology combined with improved coiled tubing services have resulted in the successful completion of an abnormally pressured, multi-zone horizontal producer. An operator was planning to develop a horizontal completion in the Gulf of Mexico and required a design that would successfully address certain unusual reservoir conditions; i.e., the primary zone was abnormally pressured, and below the primary zone, there was a secondary reservoir that could not be accessed unless an additional well was drilled or the initial well depleted and a sidetrack performed.

To enhance the economic and operational feasibility of the completion, the operator needed a well design that would address the above pressure conditions and allow production from either or both zones.

This paper will discuss the methods and equipment that were used to successfully provide the project needs.

The completion configuration that was finally adopted utilized a concentric production string with pre-packed gravel pack screens, an external casing packer and multiple sliding sleeves in the concentric production string to provide the zonal isolation as well as wash-down capability since wash pipe would not be run. Significant in the success of the completion was the use of computer simulation of the coiled tubing operations to confirm capability to provide the required forces, and the use of a new sliding sleeve device that only required 500 pounds of shifting force to operate as opposed to three to five times that amount normally required to shift conventional sleeves. In addition, the sleeve had demonstrated superior operational integrity in conditions similar to those expected in this completion in which shifting forces usually caused premature equipment erosion.

The case history will provide information concerning the development of the completion as well as the actual completion scenario and how the completion design allowed fluid losses to the formation to be minimized during the completion phase.

This success demonstrates the capability to complete in several zones with isolation potential in abnormally pressured reservoirs and in completions with depths in excess of 13,000 ft. The use of advanced coiled tubing techniques and the new sliding sleeves that could maintain operational integrity in extremely corrosive environments enabled the job parameters to be met.
Serviceability of Coiled Tubing for Sour Oil and Gas Wells
Authors: Cayard M.S. , Kane R.D.
Published: December 2007

Coiled tubing is an extremely useful tool in many well logging and workover applications in oil and gas production operations. Several important concerns regarding its use include the need for improved guidelines for the assessment of mechanical integrity, fatigue damage, and the effects of hydrogen sulfide in sour oil and gas production environments. This paper provides information regarding the use of coiled tubing in sour environments with particular emphasis on sulfide stress cracking, hydrogen induced cracking and stress-oriented hydrogen induced cracking and how they work synergistically with cyclic cold working of the steel tubing.
Coiled Tubing Injection-Well Cleanouts with Tapered-OD Strings
Authors: Love Douglas , Mullins Rufus , Brelih William A.
Published: December 2007

This paper presents a case history in which a tapered-OD coiled tubing (CT) workstring and a blast nozzle were used for cleanout and stimulation work in a west Texas well. The tubing's tapered OD allowed it to pass through restricted downhole IDs while maximized flow rate was maintained. These techniques resulted in greater cleaning energy, higher annular velocities, and reduced pump times.

The workstring used was primarily 1 ¼-in. OD, but it was tapered to 1 in., and then to ¾ in. The ¾-in. portion was the only part of the string that penetrated beyond the depth of the shutoff valve in the injection string. A single injector head with a vee-block design allowed for smooth size transition as the tapered string was run in and retrieved. Three or four passes of the coiled tubing length were made with the blast nozzle.

Conventional tubing cleanouts in this field require approximately 10 to 14 days; however, by using the tapered CT string and a body-load coiled tubing unit (CTU) operators can perform such treatments in 8 to 10 hours. In addition to injection-well cleanouts, other potential applications for tapered-diameter CT are presented in this paper.
Effects of Coiled Tubing Shear History on the Rheological and Hydraulic Properties of Fracturing Fluids
Authors: Shah S.N. , Subramanian R.
Published: December 2007

Coiled tubing shear history effects on the rheological and hydraulic properties of various fracturing fluids are investigated using the experimental equipment available at the Fracturing Fluid Characterization Facility (FFCF), located at the University of Oklahoma. The primary investigation includes tubing curvature effects on the frictional pressure losses using various lengths of coiled tubing and on the fracturing fluids apparent viscosities, over a range of selected linear and crosslinked fluids, using a unique High Pressure Simulator (HPS), capable of operating at elevated temperatures and pressures. To ensure a comprehensive understanding of the curvature effects on the rheological and hydraulic properties of the selected fracturing fluids, both coiled and straight tubings are investigated. The results show that coiled tubing curvature increases the frictional pressure losses for fluids such as water, linear guar gum and Hydroxypropyl guar (HPG), and borate-crosslinked guar and HPG fluids. Also, the study shows that frictional pressure losses within a coiled tubing are dependent of coiled tubing shear history for borate-crosslinked HPG gels and are independent of coiled tubing shear history for borate-crosslinked guar gels. On the effects of coiled tubing shear on the rheological properties of the fracturing fluids, the study indicates that apparent viscosities of borate-crosslinked gels are a function of shear history, pH, and temperature. Furthermore, the results show that for certain fluids, there exist an optimum pH, where shear history does not affect fluid's apparent viscosity.
Accuracy and Reliability of Coiled Tubing Depth Measurement
Authors: Pessin J-L. , Boyle B.W.
Published: December 2007

Coiled Tubing Depth Measurement has become more critical with the advent of new coiled tubing services, such as logging, drilling, perforating and zonal isolation. For depth critical applications, multiple depth correlation measurements are often made using expensive down hole tools. A reliable measurement system can significantly lower costs and simplify logistics by reducing the need for multiple depth correlation measurements. This paper presents the results of a comprehensive study of the causes of depth errors, and proposes a strategy to improve reliability and accuracy of the depth control.

The causes of errors with depth are classified in four categories: errors of reference; errors of procedure; errors of surface measurement; and errors due to down hole deformation of the Coiled Tubing.

The order of magnitude of these errors prioritizes a depth control strategy based on: the elimination of reference and procedure errors by providing computer tools; a new surface measurement system that emphasizes the role of repeatability versus accuracy; and the use of the pipe models. Based on this strategy, we can improve the reliability and accuracy of depth measurements and limit depth correlation to the necessary cases.

Results can apply to all coiled tubing operations, particularly zonal isolation, perforating, drilling and logging.
A Case Study of Downhole Obstruction Avoidance for CT-Conveyed TCP Operations
Authors: Conrad A. Bruce
Published: December 2007

Tools such as mud motors, indexing tools, and hydraulic kickovers use pumping for rotation or lateral displacement. In special cases, however, coiled tubing operators must manipulate coiled tubing (CT) bottomhole assemblies (BHA’s) without the benefit of pumping.

On this occasion the production company’s tubing-conveyed perforating (TCP) guns did not fire. Operators cut the guns off, expecting them to drop in the rathole, but instead, the guns lodged in mud solids at the production interval. CT engineers had to design a toolstring that could bypass the obstruction and access the unperforated production interval with TCP guns without the use of conventional hydraulic or rotational tools.

In this particular case study, operators did not have to pump to bypass a downhole obstruction, such as a fish in a deviated wellbore; instead, they used mechanical indexing tools that had been configured into specialized BHA’s.
New Seismic on an old Field : The impact of the 1995 Brent 3D seismic survey
Authors: van Dierendonck A.I. , Pronk D.W. , Ward V.C.
Published: December 2007

As the Brent Field moved into the latter stages of field life it had become increasingly apparent that the resolution of the 1986 Brent 3D survey was insufficient to meet the demands for increased geological detail. Hence in 1995 a 320 sq.km 3D seismic survey was acquired over the field with a denser subsurface sampling than the previous survey. Compared to the previous survey the seismic resolution of this dataset has clearly improved. Fault definition is superior, especially in the so-called "slumped" areas, where a substantial portion of the field's remaining reserves are located. Detailed field wide structural maps will form the basis for the year end review of reserves and have already been incorporated at an early stage into detailed dynamic reservoir models of complex areas. The improved seismic data quality of the new survey justifies the application of "state-of-the-art" geophysical techniques to obtain additional information which could help the determination of reservoir quality characteristics and the prediction of produced fluid contacts. These techniques include Amplitude Vs Offset, Seismic Inversion, Amplitude studies, and 4D Time Lapse studies. Parallel to these initiatives continuous data processing refinements are being tested (amongst others pre-stack depth migration) in an effort to further enhance seismic resolution.

The challenge is to manage these large numbers of continuously improving seismic datasets, whilst at the same time maintaining their impact on the maximisation of the remaining value of the Brent Field.

Introduction

The Brent field, located 160 km NE of the Shetland Islands in the UK sector of the North Sea, was discovered in 1971 and production started in 1976. Hydrocarbons are produced from the Jurassic Brent and Statfjord reservoirs trapped in a westerly dipping monocline with slump (crestal collapse) features. Remaining reserves are currently estimated at around 400 MMbbl oil and 2.6 TCF gas. A new phase of development has started for the Brent field where reservoir depressurisation will gradually transform it from an oil to a gas producing field. Major efforts are now concentrated on locating and developing the field's thin remaining oil rims. It had become increasingly apparent over the last few years that the previous 3D seismic survey, shot in 1986, was insufficient to meet these demands. Re-processing of this survey, carried out in 1989 and again in 1993, had failed to significantly improve the quality of the data which considerably downgrades its usefulness. Hence a new high resolution 3D survey was acquired in 1995. In addition a high quality seismic dataset prior to field depressurisation may provide a suitable base line survey for possible future time lapse seismic surveys.
Phase 2 Development of the Slumped Crestal Area of the Brent Reservoir, Brent Field
Authors: Coutts S.D. , Jurgens M. , van Kessel O. , Pronk D. , Ward V.C.
Published: December 2007

The Brent Field consists of a major, westerly dipping fault block, with a crestal area broken up into a series of slumped fault blocks. Development of these complex slumped blocks started in 1993 and to date a series of 9 roughly parallel horizontal east-west oil producers have been drilled, some of which have subsequently been converted into water injectors. Oil production to date, at a total rate of up to 100,000 b/d, exceeds the 1993 Development Plan forecast by 11%, despite poorer than expected east-west and north-south communication in some parts of the field.

Key conclusions from the first phase of the development are:-–The Development Plan concept of multi-purpose horizontal wells (appraisal, production, injection) has been successful mainly because of the validity of the geological model. This has allowed optimal positioning of wells, with sand-sand juxtaposition initially providing sufficient pressure support via the West Flank.–Controlled reservoir depletion can be used as a method to establish fault block connectivity and to steer the flow of injection water. Uncontrolled depletion will lead to unwanted crossflow, ultimate recovery loss due to oil shrinkage and hazardous drilling due to large pressure differences.–The introduction of 7" monobore completions, combined with consecutive perforation and isolation of 150–250m reservoir sections, has increased ultimate recovery and reduced cost. Multi-straddle assemblies have proved to be ineffective, because communication patterns cannot be predicted accurately enough.

An extensive data gathering programme has now been largely completed, consisting of new 3D seismic, borehole imaging logs, radioactive tracer injection, interference testing, advanced PLT logging and permanent downhole gauge output. This has so far resulted in an adjustment to the Development Plan in the compartmentalised Brent Horst and Graben areas, successfully targeting one water injector to support two producers 1500m apart, and in one infill well to appraise the quantity and quality of reservoir rock between the top Etive and the X-unconformity erosional surface. In combination with advanced drilling techniques a recovery factor of 50% is now considered achievable.

Introduction

The Brent Field consists of a major, westerly dipping fault block, with a crestal area broken up into a series of slumped fault blocks. Development of the Brent slumps started in 1993 and to date a series of 9 roughly parallel, horizontal east-west oil producers have been drilled, two of which have subsequently been converted into water injectors (see Figure 1). The wells in question are listed (in chronological order) in Table 1. They are all part of the first stage of the 1993 Development Plan (ref. 1), eventually comprising of 6 horizontal producers, interspersed with 6 horizontal water injectors.

P. 135^
Integrating Parallel Engineering with Phased Field Development in order to Balance Cash Flow, Net Present Value, and Risk
Authors: Preece Mark , MacLeod Andrew
Published: December 2007

The future of the offshore oil/gas industry in the UKCS faces a growing number of challenges. Not least of these are the technical complexity of the reservoirs currently available for development, and their lower recoverable reserves.

Current exploration and production efforts are concentrating on either stand alone small/marginal fields or brown field developments, exploiting hitherto untapped reserves near to existing facilities.

Technical advancements are playing their role in enhancing the ability of operators to reduce development costs. The greatest constraint on extracting the maximum value of these reserves is, however, the field development process. This constraints can only be overcome by introducing new business and engineering processes which are focused on achieving both the goals of the operator and of the field development contractor.

An integrated field development contractor, with access to key technology, personnel, and equipment, can assist in the enhancement of the value of these small/marginal fields by structuring the development process such that it provides the optimal balance between cash flow, Net Present Value (NPV), and risk.
Multi Lateral Rewards in Tern Field
Authors: Roberts M. J. , Tolstyko M.
Published: December 2007

Tern Field represents a significant production asset, making an important contribution to Shell net income on a global scale. With the initial development programme having successfully developed the bulk of the Brent Etive reserves, attention is now also focused on profitable oil production from STOIIP locked in the poorer quality Ness and Rannoch formations. A new approach, driven by factors including platform slot constraints, maximising profitability and increasing production levels, has led to a development strategy which adopts multi lateral technology as a springboard to achieve identified rewards.

Well TA14, completed in Q3 1996, combined a successful exploration and appraisal of Triassic near-facilities-potential with a subsequent Brent reservoir dual-lateral oil producer: all attained in one well. Cost savings of £4.5 million have been achieved over more conventional drilling methods, together with important project acceleration. Follow up development of Triassic oil will be in 1997 via a dedicated Triassic multi lateral well (TA17), just 18 months after TAM proved the reserves. Well TA19 was planned and executed as a sidetrack multi lateral producer which targets bypassed Lower Ness oil. The results of this trial are expected to positively influence future Brent Group production operations.

Shell is actively driving the continual development of multi lateral technology and promoting longer term working relationships with integrated Service Companies. In particular, the application of geosteering techniques, slim-hole LWD logs (plus office-based real-time display), selective lateral isolation capabilities and multi lateral water injection wells represent substantial advances to maximise Tern Field oil development opportunities.
What Can The UK Oil Industry Realistically Expect to Export?
Authors: Forrest K. P. , Darbyshire B.
Published: December 2007

Introduction

Britain is a trading nation, exporting some 23% of its GDP which compares favourably with Germany and France at just below this figure, and perhaps rather surprisingly for some of you well ahead of the USA and Japan each of which have about 10%. We have over 6% of total world exports, which places us among the small group of leading exporting countries. It is therefore not unreasonable to expect that the UK should be able to export a sizeable proportion of the goods and services it provides for the oil, gas and petrochemicals industry. But before testing the validity of this statement, let us first take a look at the make-up of our oil and gas supply industry.

Companies involved can broadly be divided into two groups. First, there are those which for many years have been providing a range of goods and services to many sectors of activity. These companies were established long before the first discovery of North Sea oil and gas and are generally large enterprises making significant contributions to the UK economy.

Second, there are those which have been set up specifically to respond to the needs of the oil industry and have been in the business for a rather shorter period of time. Companies involved in this category are, for the most part, relatively small, but their capabilities are good and they have established a presence in several niche areas. One exception to this is the significant number of international contractors, mainly of American origin, which have set up in the UK initially to service the UK Continental Shelf.
Application of Downhole Video Technology to Multilateral Well Completions
Authors: Maddox S. D.
Published: December 2007

Current downhole video systems have successfully been used during the multilateral completion process. The technology is specifically being applied to the testing, inspection, and evaluation of multilateral junctions. Some examples are presented, complete with video footage from different stages in the process of building a multilateral junction.

Downhole video field data is also presented demonstrating cases of properly milled casing windows, malfunctioning whipstock equipment, and a casing window inadvertently drilled in an unconsolidated formation.
Applications of Downhole Magnetic Resonance Imaging in the North Sea
Authors: White Jim
Published: December 2007

In-situ reservoir description has recently taken a major step forward with the introduction of combinable Nuclear Magnetic Resonance (NMR) sensors. Run as a pad or mandrel device in combination with other logging tools, they can provide direct information on the properties of the pore structure and pore fluid. Much of this potentially valuable information has only been previously available from core data and formation fluid samples.

The paper will briefly review the principle of NMR measurement, then concentrate on some of the ever widening range of applications. Examples of these are taken from in and around the North Sea, and cover the following areas of reservoir evaluation.
Development and Testing of Downhole Pump for High-Pressure Jet-Assist Drilling
Authors: Veenhuizen S. D. , Stang D. L. , Kelley D. P. , Duda J. R. , Aslakson J. K.
Published: December 2007

A second generation prototype ultra-high pressure (UHP-30,000 psi) downhole pump (DHP®) for jet-assist drilling has been tested in the laboratory and downhole. The development and testing program has been supported by the Gas Research Institute (GRI) and the U.S. Department of Energy Federal Energy Technology Center (DOE-FETC). It is anticipated that with development of this technology, drilling penetration rates in the harder, slower drilling formations in gas and oil wells could be increased 1.5 to 2 times through jet-assist of the drill bit.

As with the first generation prototype DHP, the ultra-high pressure pump is designed to be located downhole in the BHA just above the drill bit. It is rated at an output pressure of 30,000 psi at about 20 gpm. Power to drive the DHP is delivered downhole via the conventional mud stream through elevating the surface mud pump pressure 1,500 to 2,000 psi using conventional flow rates downhole.

The operating principle and general arrangement of the DHP pump is discussed along with the operating behavior and performance characteristics. The pump has been tested eight times downhole in three commercial gas wells in the Travis Peak Formation of East Texas and a granite test well in Norway. Rate of Penetration (ROP) enhancements observed were up to 1.5 to 1.6 times conventional penetration rates. Testing in the laboratory to evaluate design issues that have limited downhole operating hours is summarized in terms of fluid sealing, mechanical strength, and fluid erosion. Jet-assist drilling ROP enhancement is also discussed in terms of laboratory drilling test results and field drilling results utilizing the DHP in East Texas and Norway. The main technical design challenge remaining before commercialization of the DHP technology is erosion within the pump when drilling very abrasive formations.
Advanced Sandstone Acidizing Designs Using Improved Radial Models
Authors: Gdanski Rick , Shuchart Chris
Published: December 2007

With the recent development of a comprehensive theory for the complete chemistry and kinetics of sandstone acidizing, it was appropriate to develop useful radial models for exploring and simplifying the application of the new technology. These radial models were designed to accommodate both the positive and negative aspects of the recent discoveries. These discoveries included ion-exchange transformation of brines, decomposition of clays in hydrochloric acid, precipitation of fluosilicates, removal of carbonate to prevent the precipitation of complex aluminum fluorides, silica-gel filming, colloidal silica-gel precipitation, precipitation of the various complex aluminum fluorides, mixing between the various stages of the treatment, damage removal, permeability modeling, and skin evolution. Calculations were initially performed with a comprehensive workstation-based computer model so that the magnitude of the various effects could be measured. These calculations showed that many negative effects could be minimized or eliminated by special design considerations. A PC-based model was then written that could help design engineers avoid serious problems when acidizing sandstone formations and provide them with visual guidance for some of the other issues that were relevant. The "avoiding problems" approach for the PC-based radial model provided a powerful basis for introducing advanced designs for sandstone acidizing that have dramatically improved the success rates of field treatments. In addition to choosing the correct HF fluid to avoid secondary precipitations, considerations for choice of preflushes to condition the formation proved essential. Proper choice of preflush is based on acid stabilities of the clays, carbonate removal, and the avoidance of deep clay swelling. Appropriate acid-preflush volumes help ensure carbonate removal for at least 24 in. and provide sufficient fluid spacing between formation brine and the spent HF fluids at the end of the treatment.
Wellbore-to-Fracture Communication Problems Pose Challenges in California Diatomite Horizontal Wells
Authors: Wright C.A. , Minner W.A. , Weijers L. , Davis E.J. , Golich G.M. , Kikuchi H.
Published: December 2007

In an increasing number of hydraulic fracturing environments, the petroleum industry has aimed for greater cost-effectiveness through the use of horizontal wells instead of conventional vertical wells. Several recent examples where this strategy has been evaluated include the giant Belridge oilfield where three horizontal wells have been drilled with an oblique orientation of roughly 700 to the preferred fracture orientation (determined by the existing well pattern), and completed with multiple propped fracture stages. In the past, industry has focused much attention on the connection between transverse hydraulic fractures and horizontal wellbores, primarily to avoid bridging screen-outs in the near-wellbore tortuous region. It was assumed that if the proppant could be placed successfully, then the fracture stimulation would be successful.

However, in the soft diatomite rocks in the San Joaquin Valley, a different problem has emerged. While premature screen-outs have not been a problem, the complex character of hydraulic fracture initiation in this rock has impeded the creation of a sufficiently conductive connection between the wellbore and the primary propped fracture(s). Integration of several diagnostic techniques (such as net fracture pressure analysis, tiltmeter fracture mapping, Hydraulic Impedance Testing (HIT), post-fracture production logging and video logging) reveals that the poor wellbore-to-fracture connection is due to the complex initiation of multiple hydraulic fractures along the horizontal wellbore, many of which are not effectively connected to the perforations. Despite appropriate far-field propped fracture penetration in the reservoir zones of interest, connection between the reservoir and wellbore is compromised because the main propped transverse fracture can be displaced 10 – 100 ft along the wellbore away from the perforated interval, This breakdown in wellbore-to-reservoir connection can severely damage well productivity, in extreme cases reducing individual stage contributions to zero. Figure 1 shows a conceptual sketch of what the actual fracture geometry induced from a single stage may look like. Note the small longitudinal fracture that runs along the wellbore and the many transverse fractures that leave the wellbore away from the perforated interval.

As petroleum production from transversely fractured horizontal wells has been successful in other environments, it is believed that the severity of the problems encountered with these wells was due the specific environment conditions (3D-stress state, rock properties, poor cement quality, etc.). However, these same problems are likely to occur, perhaps to a lesser degree, in many environments.

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A Procedure to Integrate Well Test Data, Reservoir Performance History and 4-D Seismic Information into a Reservoir Description
Authors: Landa Jorge L. , Horne Roland N.
Published: December 2007

This paper deals with the problem of estimating the distributions of permeability and porosity in heterogeneous and multiphase petroleum reservoirs by matching the dynamic behavior. The dynamic data is in the form of field measurements from well testing, production history, interpreted 4-D seismic information, and other data such as correlations between permeability and porosity, geostatistics in the form of a variogram model and the inference of large scale geological structure.

The issue was posed as an inverse problem and solved by using nonlinear parameter estimation. The procedure developed here is capable of processing all the information simultaneously and this results in a fast and efficient method. The procedure is also able to determine the uncertainty associated with the estimated permeability and porosity fields.

Examples of different parameter types that may be estimated by this approach include: (a) individual block permeabilities and porosities; (b) geological objects such as channels and faults; (c) pilot points that form the basis of a kriged distribution; and (d) seismic attenuation values from 3D seismic images.

An important conclusion of this work is that the value of each piece of information does not reside in its isolated use but in the value it adds to integrated analysis of the complete set of information. Thus data that traditionally was considered to be of low information content for reservoir characterization becomes useful and enhances the value of the data set as a whole.