bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Solution of the Material Balance Equations of Compartmented Gas Reservoirs
Authors: Hagoort Jacques , Hoogstra Rob
Published: December 2007

This paper presents a robust and rigorous method for the numerical solution of the material balance equations of compartmented gas reservoirs. The method is based on the integral form of the material balance equations and employs an implicit, iterative solution procedure. The proposed method enables extension of traditional p/z analysis of single gas reservoirs to complex, compartmented gas reservoirs.

Example calculations of the depletion of a compartmented reservoir show how the p/z is affected by crossflow, reservoir size and depletion rate. The depletion behavior can be rationalized by the observation that depletion of a compartmented reservoir at a constant rate tends to develop a semi-steady-state. A field example is presented that illustrates the capabilities of the extended material balance for the analysis of the past performance of compartmented reservoirs.
An Efficient PC Based Streamline Simulator for Immiscible and Miscible Displacements
Authors: Peddibhotla Sriram , Spath Jeff , Batycky Rod P.
Published: December 2007

Optimizing immiscible and miscible floods are important applications of reservoir simulation. Other important applications include reservoir characterization, history matching, forecasting for project decision making and assessing uncertainty in all the above. Any simulation approach used for these applications should be accurate, reliable, easy-to-use and efficient. Streamline simulation has emerged as an attractive simulation approach that satisfies all of these requirements. In this paper, we describe a new PC based streamline simulation software (STREAM) which allows engineers to quickly simulate and visualize immiscible displacements (waterflooding) and miscible displacements (CO2 flooding). The streamline model is written in FORTRAN90 and the GUI is written in Visual Basic 4.0. Details of the development and the operation of the software are discussed.

Using STREAM, we present a comparison of results between the streamline and traditional (finite-difference) simulation for a mature, West Texas waterflood. The efficacy of the streamline approach and the capability of the software for waterflood optimization is discussed. Timing comparisons between the two methods are also presented. Finally, the advantages and limitations of the streamline method for both immiscible and miscible applications are discussed.
Assessment of Jet Perforated Rock Damage by Finite Element Method
Authors: Asadi M. , Ghalambor A. , Shirazi M. K.
Published: December 2007

Finite element method has been employed to evaluate stress distribution within the sandstone formation as the result of a perforation job. The study is based on the followings: a radial reservoir with a perforated well located at the center of the reservoir, characteristics of both 3.5 and 10.5 gr. RDX charges, and the mechanical and thermal properties of the Berea sandstone. This research was performed in three distinct steps: 1) jet temperature effect, 2) jet pressure effect, and 3) combined jet temperature and pressure effects. The results indicated that a 3,5 RDX charge with 2,500,000 psi initial pressure is capable of disturbing rock formation up to five inches longitudinally and two inches radially. The extent of this damage zone for a 10.5 gr. RDX charge having an initial pressure of 4,000,000 psi is eight inches longitudinally and four inches radially. The linear effect is within the first few inches of the perforation runnel entrance. Within this region, rock grains are under an intensive sudden shock pressure wave of 2 to 4 million psi for fraction of a microsecond As a result, rock physical structure will change to metamorphous with a lower bulk density than that of un-shocked rock, causing a sudden decrease in formation porosity and hence formation permeability. This study however, shows that thermal stresses as the result of jet temperature (1,200°F), is insignificant.
Criteria for Back Production of Drilling Fluids through Sand Control Screens
Authors: Marken Craig , Markestad Per , Rorvik Ola
Published: December 2007

By setting sand control screens for open hole completions in the same fluid that was used for drilling into the reservoir, considerable cost savings can be realized through the elimination of the need for displacing to a specialized completion fluid. The control of the particle composition of fluids is crucial in preventing the plugging of the sand control screens. Conditioning the fluid with fine grade shaker screens for removing the larger fluid particles is sufficient to decrease the amount of screen plugging when back producing the drilling fluid in the annulus between the screen and formation. Fluids with a lower solids loading are also beneficial for reducing screen plugging. Particle size distribution measurements have been found to be insufficient in comparison to direct laboratory evaluation the screens at predicting sand screen plugging.

Introduction

Large cost savings are possible if long, horizontal wells can be completed with a sand screen in an open hole instead of gravel packing. The completion costs can be reduced even further if the well can be drilled and completed in the same mud, without using any clean-up fluids or dissolvers. Also, the use of clean-up fluids to remove the drilling mud and filter cake has been shown to increase formation damage in many cases.

Drilling fluids are designed to plug the pores in the reservoir rock and form a thin, impermeable filter cake. It is reasonable to assume that in a sandstone the largest pores will have approximately the same size as the smallest sand grains. Because sand control screens are design to retain the formation sand, they have slots that are narrower than the largest sand grains. Thus, the slots of the sand control screens are not much larger than the largest pores in the reservoir rock.

This means that an operation where the drilling mud must be able to plug the largest pores in the formation sand without plugging slots of the sand control screens, requires very careful planning and control, both of the drilling mud, and of the slot width of the sand control screens. The risk of plugging the sand control screens will be high. For the safe execution of such operations a good understanding of the plugging mechanism is required. One must be able to predict the screen slot width that is required to avoid plugging by a mud with a certain particle concentration and particle size distribution. It would also be useful if one could predict the volume of drilling mud that could pass through a certain screen without plugging it.

When the sand control screen and drilling mud have been chosen, the particle size and concentration of the drill cuttings in the mud must be carefully controlled when drilling through the reservoir. The size of the mud solids can be controlled most easily during drilling by changing the screen in the shale shakers. For this reason it is very important to know what size of openings in the shale shaker screens are required to avoid plugging of a certain sand control screen.
Causes of Sand Control Screen Failures and Their Remedies
Authors: Hamid S. , Ali S. A.
Published: December 2007

A number of completion failures have occurred recently in which screen erosion or plugging has been found to be the primary cause. The screen failures, which occurred during high-rate water packs, have been successfully duplicated in the laboratory through large scale tests. Through these tests and mathematical analyses, the mechanisms involved in the erosive screen failures have been identified. Partial plugging of the screen in the presence of fines leads to high fluid velocities, which cause erosion of the screen by the passage of solid particles through the screen openings. The time required for the erosion to reach critical levels is fairly short i.e. on the order of a few minutes. A number of design and operational guidelines have been suggested to prevent screen failures. A characteristic pressure signature of a screen failure, which can be used for diagnostic purposes, has been identified.
Remote Automatic Control Of Oil Production
Authors: Bayless C.R. , Daughtrey Joe W.
Published: December 2007

The era is approaching when electronic equipment similar to that used by many pipeline companies for the remote control and supervision of pipeline stations may be applied to the production phase of the oil industry. The basic circuits are now being field tested by the Gulf Refining Co. in Timbalier Bay, La.

Introduction

In 1947, the Gulf Oil Corp., as other major oil companies, began developing various systems of automatic lease producing equipment. The early installations were made in the East Texas field and usually consisted of a tank switcher with time-clocked, electric valves for well control. While performing all the operational duties connected with delivery and routing of production from the well to the proper tank, these control systems have safety devices installed on separators, heater-treaters and stock tanks which, upon malfunction of any part of the operation, result in the closing-in of all related wells until conditions have been restored to normal. Such installations have reduced the labor involved in the routine production of oil remarkably. Payouts often are six or eight months. Usually only a few minutes a day supervision are required for the daily tank gauge and routine checks.

The adaptation of this or similar automatic production equipment to other than the East Texas field has been rather slow; however, the increasing development of production in the bay areas and offshore in Texas and Louisiana has given rise to many problems, of which some will undoubtedly best be solved by the application of automatic equipment. To evaluate the feasibility of such a venture, the Gulf Refining Co., in 1952, installed an automatic control system in its Weeks Island field, Iberia Parish, La.

Unlike East Texas, these wells have much higher flowing pressures and operate 24 hours per day; therefore, no timing device for proration of the well is needed at the well head and the well is subject to closure by the control system only when there is a failure of the associated receiving equipment or when the stock tanks are full.

To eliminate the necessity of building a distribution system or laying electric cable to the well for control purposes, a pneumatic system was tried with the flow line acting as the controlling medium. The valve on the well is a pressure operated diaphragm type and is controlled by a bourdon tube type pilot with a high-low shut off. Operating gas for the pilot is obtained from a fabricated drip or scrubber located down stream from the valve. By electrically opening or closing a valve on the battery manifold, the flow line pressure is released or the line is "pressured-up" and, in turn, operates the diaphragm type valve at the well head and effects an opening or closure of the well corresponding to the electric valve on the manifold. A very similar electrically operated valve is also located on all tank filling lines. Working in conjunction with a float switch, this valve provides for a method of electrically directing the oil produced into a tank and a means for determining when each tank is full.
Gathering Gas from Annular Space in Wells in El Tordillo Field
Authors: Buchanan Alejandro , Berra Ricardo , Alvarez Luis , Diaz Alberto
Published: December 2007

El Tordillo oil & gas field is located in the Gulf of Saint George basin, 40 km from the city of Comodoro Rivadavia, Chubut, Argentina. It currently has 380 active wells, using mechanical pumping, distributed over 11,500 hectares.

The produced fluids are collected in 20 batteries. The gas is distributed through a network of gas pipelines with working pressures between 4 kg/cm2 and 7 kg/cm2, depending on geographical location.

Temperatures in the winter can reach as low as −15 C.

The location of field in Argentina is shown in Figure 1.

The produced gas is processed for local sales, in addition to its use in heating and treating oil, and the generation of electrical energy.

This paper describes the studies and tasks performed in order to the capture gas from the casing-tubing annulus, the results obtained in the first stage of the project and the prospects for a wider-scale implementation.

Introduction

The wells in El Tordillo field which work with mechanical pumping produce a GOR on the order of 80–100 m3/m3 with average of water cut of 78%, with gas production totaling 300,000 m3/day. Chromatographic analysis of the captured gas reveals the following molar composition: N2:1.8%; CO2:0.9%; CH4:89.9%; C2H6:3.2%; C3H8:1.5%; iC4H10:0.3%; nC4H10:0.7%; iC5H12:0.3%; nC5H12:0.5%; others:0.9%.

The productive formations are El Trebol (1,400 mts.), Comodoro Rivadavia (1,700 mts.), and Mina El Carme (2,400 mts average depth). The production of hidrocarbons via mechanical pumping methods is complicated by the gas associated with the high liquid flow rates coming from more than 70 productive sands over a large vertical section.

The presence of liberated gas in the liquid stream extracted by the pump not only decreases the volumetric pump efficiency, but also generates stress conditions which shorten the life of the pump and the other materials and equipment in the system.

The alternatives to separate gathering & processing of the production gas are:Venting the gas to the atmosphere through the annular space, thereby producing contamination of the environment and loss of the gas, an option of limited viability owing to the new venting limits being established in the current legislation in Argentina (S.E. 236/93).Pumping the gas with the oil and water up through the tubing, with the already mentioned loss of efficiency and increase in costs.

Because of the undesireability of the alternatives and with an increased gas demand for oil treatment and generation of electrical energy, it was decided to analyze the possibility of capturing the gas independently from the annular space in the producing wells.

Well Testing

An intense well testing campaign was performed to measure and test gas flow rates, using an orifice meter in order to determine the availability of gas.
Expected Evolution in the Prices of Fuels for Electricity Generation in Argentina
Authors: Bravo Victor , Kozulj Roberto
Published: December 2007

One of today's great mysteries is the future evolution of the price of fuels for the generation of electricity. This is due both to the uncertain evolution in the price of oil and oil byproducts and to the impact of deregulation in the price of natural gas at wellhead in the medium and long term, as well as to fluctuations in the supply price of electricity within a deregulated and diversified system such as the Argentine one. The present work delves into these matters and provides a joint forecast of the price of the main fuels for electricity generation under different hypothesis combinations. At the same time, it includes a brief analysis of the repercussions which a price increase of natural gas at wellhead would have on electricity costs and contrasts such forecasts with those arising from different supply scenarios, referring the analysis to average annual monomial prices from the wholesale electricity market.

Furthermore, limitations are pointed out as regards information and methodology limitations to carry out forecasts with predictive rather than informative value, notwithstanding the inclusion of means to deal with uncertainty.
The natural gas composition in transport by pipelines
Authors: Casares Carlos A. M. , Lanziani José Luis
Published: December 2007

The design and operation of a gas pipeline requires, as a rule, considering the composition and average specific gravity of the gas already transported or to be transported.

Now the truth is that such gas will not always have the same composition or specific gravity, given the fact that it varies significantly from winter to summer, and that it can even change along the pipeline.

This paper was done with the intention of showing the effects that those changes can have in transportation capacity, power used and in transported energy. In order to do so, we based our study simulating Steady-Flow conditions and considering extreme situations.

The basic principle "equal transported volume does not imply equal transported energy or equal mass" was a clear evidence in our study, and in some cases the differences were significant.

At the same time this is particularly important because we can appreciate the implications of using commercial criteria indistinctly, for instance the sale of energy volumes, transportation of mass volumes or design criteria.

The main objective of this paper, then, is to learn about natural gas composition -as far as transportation is concerned-both for the design and operation of a pipeline.
The Prado Basin Oil Wells: A Case History
Authors: Hesson Bruce H.
Published: December 2007

In 1941, the Prado Dam was built in Riverside County, California, near the City of Corona. In 1965, one federal and one private lease were granted for oil and gas exploration behind the dam. The federal lease stipulated that "…all rights under this lease are subordinate to the right of the United States to flood and submerge the lands, permanently or intermittently in connection with the operation and maintenance of the Prado Flood Control Basin Project."

Thirteen oil wells were drilled and completed on these two leases and oil and gas were produced in the field from 1965 through 1993. During this period, the wells were submerged numerous times and several oil spills occurred. After an oil spill in 1993, the wells were shut in by a court order. In addition, California Department of Conservation's Division of Oil, Gas, and Geothermal Resources (Division) issued a formal order outlining corrective action to be taken by the operator to prevent another spill. The operator failed to comply with this order. To prevent another spill, the Division undertook remedial action over a three-year period. Finally in 1996, the wells were plugged and abandoned when the operator failed to comply with the formal order and it was determined the wells were an environmental hazard.
Waterflood Optimization Using a Combined Geostatistical – 3D Streamline Simulation Approach: A Field Example
Authors: Spath Jeff , McCants Steve
Published: December 2007

Stochastic reservoir description techniques are combined with a three-dimensional streamline simulator to optimize volumetric sweep efficiency in a mature, West Texas waterflood. Results from the streamline model were validated using an IMPES, finite-difference scheme. It is shown that the combination of multiple-realization property distribution with an efficient streamline model is an attractive alternative to the traditional, finite-difference approach. Performance predictions are made for the placement of new infill wells (vertical and horizontal) and for pattern modification by selectively shutting in existing injectors.

Geostatistical techniques including kriging and cokriging are used to generate realizations of property distributions. Fundamental to the geostatistical techniques described is the honoring of hard data and we illustrate the importance of integrating various data sources to constrain these techniques. Specifically, production, core, log, pressure transient, geological and 3D seismic data were combined to estimate near-well properties and to place realistic constraints on distributing porosity, permeability and net-to-gross thickness.

The advantages and the applicability of the streamline approach are outlined as well as the caveats. Primarily, it was found that streamline simulation is much more efficient in solving two-phase, immiscible problems and produces results equivalent to finite-difference methods.
Cut-off or Separation? A New Approach to Distinguish Reservoir Rock from Non-Reservoir Rock for Reservoir Modeling and Simulation
Authors: Li Dachang , Dria Myra A.
Published: December 2007

The term ‘cut-off’ refers to a joint effort by geoscientists and engineers to define a value which discriminates non-reservoir rock (shale) from reservoir rock (sand), and has been used in the petroleum industry for several decades. In many instances a single cut-off is not good enough to define sand requiring the use of additional variable cut-offs. The determination of cut-off(s) is highly dependent on a geoscientist's or engineer's experience. There exists no well-defined method that is built on a sound scientific basis.

A systematic method is presented in this paper. The new method separates reservoir rock from non-reservoir rock based on the statistical properties and probability distribution functions derived for the various properties of a reservoir interval. It is common that the histogram of a variable (i.e. porosity) has a mixed interval between reservoir and nonreservoir rocks.

No matter how a cut-off is defined on the histogram, there will always be a number of values that are incorrectly classified. As a result, we have seen errors in hydrocarbon volume calculation which have been in the range of 5 to 30 %. Unlike the typical application of cut-offs, the proposed method identifies a boundary (no or little mixing) between the two rock populations and then separates them based on this boundary. Correct boundary identification, by analyzing all available variables collected from well logs, is the key to success. When there is no clear boundary, integration of engineering data (i.e. relative permeability and capillary pressure) with the well logs helps to identify possible boundaries or cut-offs.

A field study demonstrates the principle of the new method and the improved results includes more than 80 wells. The method is easy to understand and to apply in practice.
Managing Technology Development for Productivity Enhancement
Authors: Currie Peter K.
Published: December 2007

Shell has recently re-organised its EP Research & Technical Services. This paper describes the philosophy and evolution of the new organisation, and its consequences for the generation and application of productivity enhancement technology.
Coiled Tubing Drilling Case History, Offshore The Netherlands
Authors: Gunningham M.C. , Coe B. , Evans S. , Wiersma J.
Published: December 2007

This case history outlines a recent coiled tubing (CT) drilling project in the Dutch Sector of the North Sea. Operations were conducted from a jackup drilling unit. The drilling unit conducted preliminary operations, commenced the sidetrack and recompleted the well. CT was used to drill the reservoir section of the new hole.

For CT, the objective was to exit through the 5-in. liner shoetrack and drill 230 ft of a 3 3/4-in. directional hole. The surface equipment had been designed to allow for the CT to be stripped out of the hole if substantial drilling fluid losses occurred. In this case, the well would be cleaned up and tested and the 3 3/4-in. section left barefoot. In the event that drilling fluid losses did not occur, then the section would be drilled overbalance with a low toxicity oil-based mud (LTOBM) and a 2 7/8-in. slotted liner deployed.

The 5-in. shoe track was cleaned out successfully with a mill and a positive displacement motor. The 3/4-in. hole section was drilled from 12,276 ft to the required total depth at 12,486 ft in 33.5 hours with one bottomhole assembly (BHA) and bit.

This case shows that with the proper planning, detailed design and execution, CT drilling can provide a cost effective alternative for drilling sidetracks.
An Operational Overview of the Use of High Pressure Coiled Tubing in the Gulf of Mexico
Authors: Larsen Henrik Aslak
Published: December 2007

Coiled Tubing (CT) has successfully been utilized to enter wells in the Gulf of Mexico (GoM) with well head pressures up to 7500 psi. Several different applications has been applied to high pressure wells, thereby yielding savings to the operators and increasing the operational safety. The equipment is presented along with the CT material selection. The business mix and operational statistics are presented and discussed.
Utilizing Coiled Tubing in Mobile Bay's 22,000 TVD Gas Wells Yields Economical and Technical Advancements
Authors: Larsen Henrik Aslak , Kenrick Anthony , Bell Robert
Published: December 2007

It is desirable to pursue the coiled tubing (CT) as an alternative to snubbing in performing through tubing work over operations. With the advances in high pressure CT, it is feasible to contain high pressures. High yield strength (100,000 psi) coiled tubing material has allowed for coiled tubing intervention in the Mobile Bay Norphlet completions. These wells are approximately 22,000 feet vertical depth, high pressure, Hydrogen Sulfide (H2S) gas wells.

The operations performed include:A scale clean out to approx. 22,000 feet.A HCl acid job has been performed at 415F.Clearing a safety valve from build up.

The first operation performed was a scale clean out to 22,000 feet utilizing a spiral wash tool. The well was killed with a 10 ppg NaBr and the same brine was used for clean out fluid. Cost savings of 60% were realized.

The second operation was a HCl matrix acid job performed at 415F.

The third job was a scale clean out across the down hole safety valves. The safety valve was blocked by scale build up and was rendered inoperative. Remedial work was needed. If the through tubing work over did not work, a rig work over was needed. The safety valve was cleared of debris in one operational day. It is estimated that the CT operation cost less than 5–10% of a rig work over.
Positive Displacement Motor Test with Two-phase Flow
Authors: Li J. , Tudor R. , Cox R.
Published: December 2007

Underbalanced drilling with coiled tubing requires the use of a positive displacement motor (PDM) to drive the drill bit. Motor performance characteristics are essential to ensure drilling success and efficiency, and the pressure drop across the motor must be specified to accurately simulate underbalanced conditions at bottom hole. In this study, five positive displacement motors were tested under a variety of mixed ratios of nitrogen and water and different back pressures. The experimental results in this study show that the performance of PDMs powered by commingled fluids is different from water baseline tests. With the commingled fluid at the same effective flow rate, the outputs of torque and mechanical power and the pressure drop across the motor are lower than those for a water baseline test. The torque output is more sensitive to the water rate, while the RPM is more sensitive to the nitrogen rate. It was also found that back pressure has a significant impact on the performance of a PDM for commingled fluids. A higher back pressure results in a lower output of torque, mechanical power and pressure drop across the motor for constant of N2 and water rates.
Using 3D Geological Modelling and Connectivity Analysis to Locate Remaining Oil Targets in the Brent Reservoir of the Mature Brent Field
Authors: Abbots F. V. , van Kuijk A. D.
Published: December 2007

As part of the drive to locate remaining oil targets in the Brent Field prior to depressurisation1, full-field 3D static reservoir models for the main Brent Field (excluding the fault-scarp degradation area called the ‘slumps’2) were constructed last year. Both the Brent Group and the Statfjord Formation reservoirs were modelled using the Shell proprietry 3D geological reservoir and property modelling program known as GEOCAP'J. This paper briefly outlines the approach taken in the GEOCAP modelling of the Jurassic Brent Group Ness reservoir, which formed the basis for the first test-case application of a new well-clustering technique, CRF (Cumulative Resistance to Flow) which is the focus of this paper.

The CRF module is one of the latest technological enhancements of GEOCAP, developed by RTS (Shell International Research and Technical Services, Netherlands). It is a permeability-distance based well-clustering module, that calculates connected reservoir volume to perforations, using the GEOCAP 3D permeability models. Subsequent removal of these connected rock-volume clusters from the model, results in a 3D model of unconnected reservoir volume. The model can then be used to identify unconnected areas that are large enough to be considered as potential remaining oil targets. These areas then warrant further investigation as potential target locations, most importantly in terms of dynamic reservoir modelling aspects, and calibration with latest surveillance data.

The results indicate that there are still several sizeable ‘targets’ (in excess of 1 MMbbls STOIP) left in the Ness reservoir after the currently planned wells have been drilled and these are currently undergoing independent review.
The Gjallar Ridge in the Vøring Basin, NOCS: A Deep Water Challenge in a Frontier, Igneous Influenced Area
Authors: Granholm P. G. , Horstad I. , Larsen D. O.
Published: December 2007

The Gjallar Ridge Licence (PL 215) operated by Saga Petroleum is located in the western part of the Vøring Basin more than 350 km from the Norwegian coastline. The water depth in the licence is 1250-1400 metres. The nearest exploration wells in the area are located on the Nyk High 90 km to the east (drilled by BP in 1997) and two wells on the Utgaard High some 100 km to the east (Figure 1). The frontier nature of the area is reflected in large uncertainties and differences in the geological models proposed for the region.

To focus on the various aspects of the petroleum system in the Vøring Basin it was deemed necessary to instigate a series of regional geophysical and geological studies, in addition to detailed studies of a more localised nature. This was done to address trap formation and petroleum charging as well as the local influence of magmatic intrusions.

A 1600 km2 3D was shot in 1996 and the first exploration well is planned drilled in 1998 (Figure 2).
An Estimate of the Cumulative Environmental Effects of the Disposal in the Deep Sea of Bulky Wastes from the Offshore Oil and Gas Industry
Authors: Picken Gordon , Curtis Tim , Elliott Alan
Published: December 2007

This paper presents an assessment of the potential cumulative environmental effects of the deposition at the North Feni deep sea disposal site of 24 of the steel platforms presently located on the UKCS. It is argued that justification for deep sea disposal could only be made if it were possible to demonstrate significant benefits in terms of reduced risks to persons during the decommissioning process. If large steel jackets could be toppled and transported in the water in one piece, and then released at the deep sea site, this would, it is suggested, reduce the risk to personnel who would otherwise be engaged in underwater dismantling and lifting operations. Candidate structures were therefore identified as those that weigh more than 10,000te in air (the maximum single lift capacity of present heavy lift vessels), and stand in water more than 100m deep (thus permitting toppling of the whole structure under present IMO guidelines). If these structures were deposited at North Feni over a period of about 24 years, the main potential source of cumulative effects would be from the release of contaminants as the sacrificial aluminium anodes were depleted. It is estimated that some 10,700te of anodes would be deposited, giving rise to a peak daily wastage rate of 1,400kg. A modified advection/diffusion model was used to predict the possible dispersion of the dissolved contaminants away from the site of deposition on the seabed. It was concluded that the peak concentrations of all contaminants in the water column extending from 0m to 20m above the seabed would be very low, and would not exceed the coastal Environmental Quality Standard (EQS). Concentrations in the water column from 20m to 40m above the seabed would be an order of magnitude less than those found near the seabed.
Gannet E: The World's Longest Subsea ESP Tie-Back
Authors: MacFarlane J. S.
Published: December 2007

Gannet E is a 20 API crude reservoir located 14 km away from the Gannet A platform. Reservoir properties make artificial lift essential to produce the fluids back to the platform. During conceptual design an ESP was selected as the chosen option due to uncertainties surrounding reservoir and fluid characteristics. Subsea ESPs are in operation elsewhere in the world (Petrobras Carapeba and Amoco Lihua), but these are in close proximity to the processing platform. The 14 km distance of the Gannet E field from the Gannet platform introduces some major technical challenges into this subsea ESP installation. ESP reliability has been poor in the past, and, when combined with a subsea installation, this can become a major Opex burden. To avoid this the Gannet E project established a project goal of achieving a two year run life from the first pump. This paper discusses how the project team addressed the technical challenges of the project, and gives feedback on progress achieved since start of production in July 1997.
Subsea Electrical Submersible Pumps At Large Step-Out Distances
Authors: Al-Mashgari Ahmed , Breit S. , Christmas Dave , Leslie Dave , Smith John
Published: December 2007

As the main reservoirs get depleted, operators are looking increasingly into the satellite fields that hold oil but in quantities that would not justify building a dedicated platform.

Consequently, methods of extracting the oil from these reservoirs by using existing facilities have been investigated. One of the most viable options is to utilize the existing mother platforms to accommodate all the topside electrical equipment, and extend cables up to a distance of 30 kms to the wellheads.

The purpose of this paper is to illustrate the work done by Reda in developing a computer software model to simulate the complete electrical system, and thus predict any problems that might be encountered in a real system. The model was verified by practical data obtained from tests conducted in the Reda, Inverurie (Scotland) and Reda Bartlesville (USA) facilities.

The program was designed to simulate various variable speed drive (VSD) power sources and model the effects of different lengths of cable to determine what combinations of VSD, cable parameters and downhole motor operating conditions would have on the total harmonic distortion.

Introduction

With the cost of intervention of an electrical submersible pump (ESP) reaching 5.6 million US dollars, weather permitting, and reliability still being an issue, operators are interested in ensuring that all possible scenarios that could be encountered are investigated in advance of installation.

One of the main concerns are the ever increasing levels of electrical Harmonics in the system due to the nature of the electrical systems.

Before we progress further it is worthwhile mentioning the four main factors that determine the life of the motor. These are:-The ambient temperature of the produced fluid.The composition of the produced fluid in terms of its capacity to carry heat away.The velocity of the produced fluid past the motor.The level of losses within the motor.

It is clear that temperature is a critical factor as it has direct impact on the insulation, and it is generally accepted that the insulating material is an exponential function of winding temperature. P. 475^
Tern Optimiser Project - The World's First Offshore Closed Loop Optimiser
Authors: Purves B. , Mortimer A. S.
Published: December 2007

The world's first closed loop optimiser on an offshore platform has been installed on Shell UK Exploration and Production's Tern platform using MDC Technology's RTO+ real time modeling optimisation product. The project audit has shown that the benefits are equivalent to 2.5% accelerated oil production. These benefits are made up of 1.5% already achieved from the on-line optimiser and a further 1.0% expected from off-line optimisation.
How Well Connected Is the Schiehallion Reservoir?
Authors: Richardson S.M. , Herbert N. , Leach H.M.
Published: December 2007

The Schiehallion field lies in water depths of up to 500m and is situated on the United Kingdom continental shelf some 200km west of the Shetland Islands. The reservoir was discovered in 1993 and has been appraised with five wells. Development of the field was sanctioned in 1996, development drilling began later that year, and first oil is expected in 1998. During 1995, an extended well test (EWT) was conducted at well 204/20–5. This well was drilled horizontally through the T3la formation, which is composed of a sequence of channel sand bodies which have variable thickness and quality. The purpose of the EWT was to test the connectivity of the reservoir.

Initial transient analysis and reservoir simulation of the EWT suggested that the overall pressure behaviour was close to 'infinite acting', and no reservoir boundary effects were evident. This suggested that the well was accessing a larger connected volume than indicated by the seismically derived thickness and structure maps. Recognising that this interpretation was difficult to reconcile with the static data, the reservoir development plan positioned injector and producer locations in a manner robust to a range of reservoir connectivity outcomes.

This paper describes the objectives, conduct and initial interpretation of the EWT. It then goes on to describe how an alternative explanation of the EWT behaviour was derived by considering the potential uncertainties in the PVT data, and the results from the ongoing development well data acquisition programme. The revised interpretation requires less connected volume than the first, but the overall reservoir development philosophy of targeting producers into the main channel sands remains sound.

Introduction

The Schiehallion field is one of the largest oil fields to be developed on the United Kingdom continental shelf in the past ten years with mean recoverable reserves of 340 MMstb. It is the second development west of Shetland following the Foinaven Field, and is located approximately 200km west of the Shetland Islands in water depths of 300 to 500m (Fig. 1).

The Schiehallion accumulation was discovered in late 1993 by well 204/20-1. Oil is trapped in submarine slope reservoir sands of Palaeocene age. The discovery well identified an oil-water contact at 2064m TVDss. P. 603^
Drilling Severely Depleted Sands in the Gulf of Mexico: The Benefits of Cloud Point Glycols
Authors: McGill Mike , Seaton Simon , Valenziano Rob , Bruner Scott , Golden John
Published: December 2007

As mature hydrocarbon reservoirs become more depleted, drilling through depleted sands is becoming increasingly common. High levels of overbalance increase the risk of occurrence of lost circulation and / or differential sticking.

Recently, three Gulf of Mexico wells successfully drilled through depleted sands with overbalances ranging from 3500 to 4600 psi In each application, a glycol-enhanced water-based mud (WBM) was used. In this paper, the formulation and application of this specially formulated WBM are discussed and the results documented.

The use of glycols as additives in WBM has been increasingly common in the past several years. Work has focused on certain glycols that exhibit "cloud point" behavior. Although soluble at surface temperatures, under the correct downhole temperatures, these glycols become insoluble and form an emulsion. Dynamic filtration and lubricity data from the laboratory, coupled with field performance from the Gulf of Mexico wells indicate enhanced filtration properties. A theory for understanding the phenomenon in WBM is offered, one which exhibits many similarities to the performance of oil-based and synthetic based muds
Development of an MWD Hole Caliper for Drilling and Formation Evaluation Applications
Authors: Maranuk C.
Published: December 2007

Hole size measurements while drilling are difficult to make because the dynamic environment precludes the use of a truly mechanical device. Several MWD caliper tools, which utilize acoustic technology, are available to the industry but they typically have a limited operating range and are often integrated with other MWD sensors, such as a density or sonic tool.1,2,4

Technical issues which could preclude the use of acoustics for an MWD caliper tool include the noise associated with the downhole drilling environment, tool accuracy, tool reliability, and errors associated with mud attenuation and signal detection, tool eccentering, formation cuttings, gas, etc.

This paper describes the design and testing of a new MWD acoustic caliper tool. The tool has been designed with its own processor, memory, power supply, and surface communications port, so it can be run in a standalone mode or integrated with other MWD sensors. This new sensor utilizes new digital signal processing technology, which increases its accuracy and operating range, when compared to previous MWD acoustic caliper tools.
A Systematic Approach to Developing Engineering Data for Fracturing Poorly Consolidated Formations
Authors: Upchurch E.R. , Montgomery C.T. , Berman B.H. , Rael E.L.
Published: December 2007

This paper presents a methodology for acquiring the engineering data necessary to develop a successful fracture stimulation campaign in a soft unconsolidated formation. This methodology was applied to a zone containing highly laminated sand/shale sequences, in which the sands are unconsolidated and easily damaged. The methodology, however, could be applied to any zone. The zone of interest has historically produced at low rates and contains significant untapped oil reserves. Thus, it is an attractive candidate for fracture stimulation. The success of this new fracture program requires a fundamental understanding of reservoir properties and, necessarily, an efficient method for obtaining those properties. To fulfill such a need a systematic data development procedure was formulated and implemented.

This paper provides the reader with an understanding of the tests conducted the interpretation of the data, the design approach taken, the operational activities, and the resultant well performance.

Introduction

In April 1996, Thums Long Beach Company embarked on a program to fracture stimulate a highly laminated but unconsolidated shale/sand stone sequence. All prior completion and stimulation techniques were unsuccessful in yielding significant oil production from this zone. These unsuccessful completion attempts consisted of various open-hole and cased-hole gravel packing scenarios coupled with non-damaging drilling fluids and post-completion acid stimulations. The unsatisfactory productivity of these completions and the considerable remaining reserves in this zone are the impetus for this fracture stimulation program. The zone of interest is the lower half of the Ranger Zone in the Long Beach Unit of the East Wilmington Field.

The Long Beach Unit of the East Wilmington Field lies under and immediately off the coast of Southern California adjacent to the City of Long Beach (Fig. 1). The productive areas of the field cover 4900 acres (1983 ha). The Wilmington Field was discovered in the 1930's but development of the offshore portion of the East Wilmington Field was not initiated until 1965 with the construction of the Long Beach Unit oil islands.

The Long Beach Unit of the East Wilmington Field is composed of three major producing zones: the Ranger. the Terminal. and the Union-Pacific-Ford. Each is part of a northwest-southeasterly trending anticlinal structure that is highly stratified with interbedded shales and sandstones (Figs. 2 and 3).

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Triptank Levels After Pumping a Slug
Authors: van Wijk J.
Published: December 2007

Pumping a heavy slug is done to allow pulling of "dry" pipe. Pumping the slug minimises the mud loss on the floor and therefore improves mud volume measurements in the triptank. When pulling out of hole (POOH), the triptank volume is expected to decrease with the metal displacement of the pulled tubulars. A computer simulation showed that the triptank volumes do not always correspond to the metal displacement of the pipe when a drill string consists of components with different IDs.
Hydraulic Fracturing of High Productivity Wells in a Tectonically Active Area
Authors: Jackson M.R. , Rylance M. , Acosta L.G.
Published: December 2007

M.R. Jackson, SPE, M. Rylance, SPE and L.G. Acosta, SPE BP Exploration (Colombia) Ltd

The Cusiana and Cupiagua fields are located in the Casanare region of Colombia. Current daily production (June 1997) is of the order of 185,000 stb/d, with production due to increase substantially. The reservoirs are severely compacted quartz arenites, of low porosity but with large pore throats. This makes them extremely vulnerable to formation damage by mud invasion. The extremely high compressive strength of the rock reduces perforation penetration, resulting in high skin factors. The skin factors are rate dependent due to turbulence associated with the high production rates, production of oil below the bubble point (Cusiana) and condensate banking effects (Cupiagua).

The wells are costly to drill, so in order to maximise the production rates hydraulic fracturing has been applied. Post fracture well rates of up to 21 mstbpd have been achieved. At these rates non- Darcy flow in the fractures is extremely important, all the more so as problems with fracture-wellbore communication and the initiation of multiple fractures have been experienced at modest deviations, as a direct result of an extreme contrast between the two principal horizontal stresses. Wide variations in the minimum horizontal stress have also been encountered in this tectonically active area. The high Young's modulus of the rock limits the achievable fracture width and therefore proppant coverage. The paper outlines the progress made to date, and the results achieved in these economically significant but technically challenging fields.

Introduction

The first fracture treatment pumped by BP in Colombia was on a highly damaged exploration well, that succeeded in increasing the production rate from 1.6 mstbpd to 12.5 mstbpd plus associated gas. Following the success of this treatment it was decided to initiate a fracture programme in the Cusiana and Cupiagua fields. These fields tend to have high kh values, and therefore despite high skins can deliver reasonable production rates. However the high drilling costs, in excess of US $ 10 million per well, require high production rates to provide attractive economics. Large diameter tubing strings (usually 5.5"or 7" are run), and the challenge is to complete wells with the potential to deliver ca. 15 – 25 mstbpd.

Various techniques have been tried to overcome the severe formation damage, but to date hydraulic fracturing has proven the most successful method, despite it's associated problems. Results achieved so far are summarised below.

Results achieved to date

As at the end of May 1997 the total number of fracture treatments pumped was 13, namely:

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