bluuebunny/crossref_metadata_2025 huggingface dataset:
Applied And Engineering Aspects Of Composite Production Logging
Authors: Gross Freeman
Published: December 2007

The economic advantage of utilizing production logging methods to evaluate well production logging methods to evaluate well conditions are, generally speaking quite obvious. Often, only one of several logging techniques has been considered necessary for a given well problem. It has become apparent that more than one or several companion logs should be run to obtain a more conclusive indication of well conditions.

The several catagories of logging systems proposed for companion use are:

Velocity Logs A. Mechanical Flowmeters B. Radioactive Travel Time Velocity Tracer Fluid Identifications Logs A. Gradient and Differential Pressure B. Radioactive Fluid Density C. Fluid Resistivity or conductivity Logs Formation Investigation Logs A. Radioactive Tracer and Nuclear Spectrographic Logs B. Temperature Logs

An in depth study of new procedures and techniques in the individual use of some of these logging tools will show surprising capabilities heretofore overlooked by a large segment of the industry.

Rather than recapping the weak points of the use of each tool the effort will be positive, objective course with the positive, objective course with the end-result the presentation of a complete diagostic and firm interpretation of the well condition.

There will be discussed new and somewhat different approaches towards radioactive tracer logging; new temperature logging techniques, and new utilization of fluid identification tools.

The data will be completely supported with numerous field and laboratory data.
Geological and Petrophysical Properties of Thinly Bedded Turbidite Deposits, Eastern Gulf of Mexico
Authors: Rollins D. R. , Shew R. D.
Published: December 2007

In this paper we discuss evaluating the geological and petrophysical characteristics of thinly bedded turbidite deposits. Shell Offshore Inc’s Deepwater Division has encountered numerous laminated to thick-bedded Miocene turbidite deposits during exploratory drilling in Viosca Knoll blocks 780, 783, and 952. The intervals are dominated by laminated reservoir quality sands and silts, non-reservoir cemented sands, and mudrocks. The sediments are interpreted as levee and interchannel deposits which are slightly consolidated, very finegrained, clay-rich, moderately compacted, and feldspathic. The thickness of many of the individual layers are below the resolution of conventional logs; therefore whole core, sidewall core, and high resolution logging tools are critical to the interpretation of reservoir and non-reservoir properties. We present detailed geological and petrophysical summaries of samples spanning the reservoir quality spectrum from massive (Ta) to rippled (Tc) facies and the non-reservoir mudstone (Tet) facies for each area.

Evaluation and prediction of thin-bed properties are necessary for 1) estimation of net pay, porosity, and kh, 2) modeling seismic response, 3) estimating compaction, 4) designing gravel packs and completion procedures, 5) understanding cross-fluid flow and sealing potential, and 6) input to reservoir modeling and simulations. Porosities and permeabilities are quite variable (24-30 percent and 10-800 millidarcies, respectively) in the reservoirs encountered, but there are positive correlations with bed thickness. Bed thicknesses are predominantly less than 10 centimeters and are mostly ripple-bedded (Tc) and parallel-bedded (Td). Facies and established depositional stacking patterns have been successfully used to predict well test response and as input to reservoir simulators.

We present a rock catalog format to provide a reference for interpreting lithotypes from this geographic and depositional setting as well as a methodology for evaluating these types of thinly-bedded deposits.
The Modeling of Deviated Wells and Sloping Faults With Locally Unstructured Grids: Part 1—Gridding Aspects
Authors: Kocberber Sait
Published: December 2007

Today, reservoir geometry and heterogeneity configurations can be determined more accurately than ever before. Heterogeneities can cause severe saturation discontinuities and create very non-uniform drainage patterns. Existence of deviated wells can complicate the flow domain further. It is important that the simulation grids used should represent the exact geometry of the reservoir heterogeneity and conform to the natural flow pattern around wells.

In most finite difference simulation models, the reservoir is divided into an array of topologically rectangular grid blocks. These structured grids yield efficient solution of the resulting set of algebraic equations [Wallis (1)]. However, because of their logically rectangular structure, these grids do not have the flexibility to conform to reservoir geometry and heterogeneity configurations. Specifically they can not represent deviated wells and sloping faults accurately.

Unstructured finite element grid blocks can be assembled to assume almost any shape and are better suited for geologically complex heterogeneous reservoirs. However solution techniques for unstructured grids are costlier, making locally unstructured grids a viable choice for these reservoirs.
A Heat Transfer Study for the In-Situ Combustion Process
Authors: Kuo C.H.
Published: December 2007

This paper deals with phenomenon of heat transport in underground combustion processes. It is assumed that heat is generated at a constant rate at a moving vertical combustion surface. This generated heat is transported in the fluid flow direction by convection and a portion is lost to the cap and base rock by portion is lost to the cap and base rock by vertical conduction. On the basis of this idealized model, temperature and energy distributions during the combustion process have been investigated.

This study indicates that it is advantageous to achieve the condition such that the heat front velocity is larger than the combustion front velocity. For this case a portion of the generated heat is carried ahead of the combustion front to heat the reservoir oil in the downstream formation. If the heat front moves slower than the combustion front, then the generated heat is distributed mainly in the formation upstream of the combustion front and in the cap and base rock.

The results of this study suggest that the combustion front temperature can be controlled in order to avoid damage to wells. This can be accomplished by controlling the rate and composition of the injected fluid.

Introduction

The in-situ combustion process is a well known method of recovering oil from an underground porous reservoir. It involves injection of a combustible fluid, e.g., air, into an oil-bearing sand. At the injection side the formation is heated by electric heaters for example for a certain period of time until the combustion becomes self-supporting. Additional heat is generated as the result of the exothermic reaction between the injected fluid and a part of the oil in place. Thus, the combustion part of the oil in place. Thus, the combustion front or reaction zone can be propagated through the formation. Simultaneously a portion of the generated heat is transported away from the combustion front. The oil is heated and its viscosity is reduced. As the result of this process, the oil moves toward the production process, the oil moves toward the production well and the flow rate is accelerated. This process has been studied both in the process has been studied both in the laboratory and in the field.

It is obvious that the phenomenon of heat transport plays a significant role in the under ground combustion process. The production of oil depends strongly upon the amount and distribution of heat which can be carried downstream from the combustion front. The present work was therefore initiated in order to study some of the factors affecting the heat distribution. The effect of the fluid flow is disregarded in this investigation.
Opportunities and Pitfalls When Locating Horizontal Wells in a Geologically Uncertain Environment
Authors: Antonsen Børre , Olsen Gudmund , Høye Trond
Published: December 2007

Horizontal wells are often much more efficient for oil production than vertical wells. However, the reservoir engineer is faced with several challenges specific for this technology both with regard to location of the horizontal section and reservoir management.

The Troll field offshore Norway will be developed by 18 horizontal wells, on average at least 800m long. The performance of the horizontal wells is very sensitive to the local geological setting. Due to large permeability contrasts, numerous calcite cemented layers and a limited database for this huge reservoir, the geological control still remains uncertain prior to development.

This paper discusses new challenges that appear when locating horizontal wells in this geological environment. The challenges of optimizing well locations and predicting well performance in an uncertain environment are discussed. The uncertainties of several parameters are considered, including: depth to reservoir sands, thickness of sands, the areal extension and position of the oil leg in high permeability sand, degree of calcite cementation within the sands, effective well length and drilling accuracy. Reservoir modeling aspects are also considered. Some important geological features have been incorporated in a stochastic model which simulates the well location management and the overall production success.
Design Considerations and Fatigue Life of Offshore Structures
Authors: Shahin M. M. A.
Published: December 2007

Results of recent studies on design of offshore structures, under hostile environment & ran-dom loading, were reviewed. This included the effects of residual stresses, weld size and crack propagation in air and see-water for both welded and threaded con-nections. Next, the design con-siderations for a successful design of an offshore structure were discussed with particular emphasis placed on material selection, compatibility, geometry, strength, fabrication, protection, maintainability and economy. Finally, practical case histories on failure of some off-shore structures were examined.
A Spoolable Coiled-Tubing Gas-Lift Completion System
Authors: Walker E. J. , Hendrix J. L. , Humphrey K. J. , Moore B. K. , Whitlow R. R.
Published: December 2007

BP Exploration and Nowcam Services have re-completed a well in the Western Operating Area (WOA) of the Prudhoe Bay Unit with a spoolable coiled tubing gas lifted completion. This completion is unique in that gas lift valves are inside the coiled tubing. Their design allows them to bend as the coil is run into the well, and prevents damage to the valve or the coiled tubing. Advantages of this system are low cost (68% below average rig workover cost) and the ability to run and pull the gas lift valves without stopping to install or remove them.

Actual running time for this re-completion was about 18 hours, with 6 of those hours needed to install the Subsurface Safety Valve (SSSV) landing nipple and 4 hours down time due to the Coiled Tubing (CT) injector chains icing up from blowing snow. After completion, the well produced 1060 bpd fluid (320 bopd) at a 1.5 mmscf/d lift gas rate. Current gross production is 750 bpd (260 bopd net) with a gas lift rate of 1.5 mmscf/d.

This re-completion is just the first step in the development of a completely spoolable coiled tubing completion system. While this job required cutting the coiled tubing to install a landing nipple for a SSSV, it is an objective to have in place by year end a spoolable SSSV system and any other necessary equipment needed to achieve a completely "slick" completion. Once achieved, it will be possible to run this system in a well without having to stop to cut the coil and install equipment.
Liquid Fall-Back Measurements in Intermittent Gas Lift with Plunger
Authors: Hernandez Ali , Maracano Luisana , Caicedo Sergio , Cabunaru R.
Published: December 2007

This work represents the first part of a three - stage research program that consists of: a) lab scale test; b) Held scale test in an experimental well and c) adjustment of existing mathematical models based on experimental test and actual oil wells.

The objective of this first stage was not to develop mathematical correlations that can be applied in the field, but to gather well controlled data that can be used to look for trends and test simple theoretical models.

The experimental results of liquid fall-back measurements in intermittent gas lift are presented. The variation of liquid fall-back with changing injection pressures, amount of gas injected and initial liquid column above the plunger are described. The plunger velocity is measured by means of proximity sensors able to detect the metallic plunger. The amount of liquid produced is determined in two ways: a) by using a weighting tank separator at the tubing outlet and b) by using pressure transducers in the bottom of the production tubing which measure liquid column height, before and after the gas injection.

The experimental work was carried out using 2 3/8" tubing of 63 ft in length. The liquid being lifted was water and compressed air was used to lift the water.
A New Look at Sucker Rod Fatigue Life
Authors: Hein N. W. , Hermanson D. E.
Published: December 2007

The ability of a sucker rod to last in a well lifted with beam pumped equipment depends on many factors. One of the principle factors is the fatigue life of the rod. Previous rod life expectations are based on the modified Goodman Diagram that resulted in the expected life of approximately 10 million cycles. These expectations are based on fatigue work that is approximately fifty years old. This paper will discuss the major factors that affect fatigue life, the improvements in the quality and manufacturing processing of rods, and the use of other stress range diagrams over the last number of years. These combined factors have now resulted in the expected fatigue life of steel sucker rods of approximately 50 million cycles. Additionally, discussed in this paper are the application of fatigue life for used steel sucker rods and the development of new allowable stress curves for used rods.
Effective Diverting on Horizontal Wells in the Austin Chalk
Authors: Bell C. E. , Holmes B. W. , Rickards A. R.
Published: December 2007

Most horizontal wells in the Austin Chalk have been completed as open hole laterals since the advent of horizontal drilling. The laterals range in length from 500 to 6000 ft. This horizontal configuration makes stimulating the entire length of the lateral zone extremely difficult. Natural fractures in the Austin Chalk and the horizontal profile preclude the use of conventional hydraulic fracturing techniques. Horizontal wells have been successfully stimulated with large volumes of treated slickwater at high rates alternately staging diverter and hydrochloric acid volumes. Wax buttons and beads have been successfully applied to divert these treatments in the open hole laterals. Wax provides effective diverting while the melting point and solubility provide ease of cleanup. This product can be manufactured in any shape or size and is a non-hazardous material.

This paper will analyze case histories of 63 wells (Table 1) stimulated over a two-year period in the Brazos and Burleson County areas (Fig. 1) of the Giddings Field. The effectiveness of the wax diverting beads will be demonstrated by Realtime Computer Analysis.1 Pre and post-production levels microresistivity logs for wellbore analysis and radioactive tracer logs2 will demonstrate wax diverters contribute significantly to the stimulation of these wells.

Selection of an effective diverting agent to optimize the slickwater fracture stimulation has evolved from treatments utilizing graded salt, benzoic acid, paraformaldehyde and naphthalene to the current use of wax beads. Product availability, solubility in hydrocarbons, cost and the lower concentrations required to achieve diversion make wax the diverter of choice for horizontal well slickwater treatments.
New Wireline Inspection System Offers Expanded Capabilities
Authors: Fehrmann G. Z. , Smith E. J. , Nolte Günter , Chitwood G. B.
Published: December 2007

One of the biggest problems facing mechanical "slickline" well servicing crews is the need to make judgmental decisions concerning the usability of wire. Miscalculation of wire condition can result in wire failures that can significantly impact economic efficiency with costly fishing operations. Premature replacement of still-useable wire to avoid the first scenario also affects operational costs, and therefore, in most cases does not offer a viable solution. Until recently, operators have had to rely on experience, "rules of thumb," visual inspection, and the "API Wire Twist Test" to determine wire integrity. These inspection methods have been limited in their capability to provide the information required to accurately determine wire condition.

This paper will present a new inspection concept that incorporates an existing, nondestructive material inspection technology into a new real-time method for determination of wire condition. The system, which employs eddy-current inspection methodology, can be used for several different applications and has the capability to provide information on various types of wire failure modes. Use of the system can:

• Ensure integrity of new wire as it is being spooled.

• Avoid costly replacement of still-useable wire.

• Facilitate general wire-life assessment.

• Inspect wire during critical service operations where well environment or operating conditions can cause rapid degradation of the wire.

Test and field operational history will be used to illustrate the capabilities and significance of the system.
An Assessment of the Effect of Fracturing-Fluid Performance on Well Productivity
Authors: Nolte K. G. , Plahn S. V.
Published: December 2007

The sensitivity of postfracture well production to fracturing fluid performance parameters (viscosity, leakoff, retained conductivity, tubular friction) is investigated. Analytic relations and numerical model simulations are used to characterize this sensitivity over a broad range of fracturing applications. It is shown that a ±30% change in a fluid parameter will generally cause less than a 10% change in postfracture production. This result should be useful to design engineers because it indicates the accuracy required for fluid data in fracture design programs. Or equivalently, the accuracy required when these data are obtained from lab or field tests.
A Consistent Procedure for the Estimation of Pseudo-Component Properties
Authors: Leibovici C. F. , Govel P. L. , Piacentino Thomas
Published: December 2007

A new method is presented for the estimation of physical properties of pseudo-components generated by any lumping procedure. Completely consistent with the equation of state to be used for the description of the thermodynamic behaviour of the lumped system, this method tends to minimize the loss of information induced by component lumping. Applied to complex fluids, it has been proved to be very effective. For illustration purposes, some results are reported for a North Sea gas condensate and a Gulf of Guinea light oil.
Reservoir Management at Ekofisk Field
Authors: Christian T. M. , Currie J. C. , Lantz T. G. , Rismyhr O. , Snow S. E.
Published: December 2007

A major field study was conducted to determine future operating strategy for Ekofisk Field. Historical and predicted performance of various IOR processes were evaluated and an IOR process was selected. The evaluation was made in the context of ongoing Upper Ekofisk Formation gas injection and water injection into the underlying Lower Ekofisk and Tor formations. Optimization of the recommended waterflood and studies of other reservoir management concerns are described. The reservoir management strategy was developed to integrate the most economical improved oil recovery process with a strategy to minimize future subsidence.
A Simulation-Based Analysis of Multiseam Coalbed Well Completions
Authors: Young G. B. C. , Paul G. W. , Saulsberry J. L. , Schraufnagel R. A.
Published: December 2007

Reservoir simulation of a coalbed methane field was used to investigate well completion and operating practices in producing gas from shallow, thin, multiple coal seams. Data from a zone isolation packer, which allows production monitoring from individual completion zones, corehole gas contents and bottomhole pressure were used to determine the efficiency of well completions and gas drainage throughout the field. The results show that wells amenable to recompletion can be identified from simulated zone isolation packer measurements; new wells can be located based on the simulated distribution in residual gas content around existing wells; gas recovery is increased by downspacing; and small increases in back pressure can reduce gas recovery.
New 3D Model for Optimised Design of Hydraulic Fractures and Simulation of Drill-Cutting Reinjection
Authors: van den Hoek P. J.
Published: December 2007

This paper presents a three-dimensional hydraulic-fracturing simulator permitting direct input of the expected net pressure at the end of a hydraulic fracture treatment – a parameter that can be readily derived from field measurements. The simulator can thus easily be used at the wellsite to generate field-calibrated fracture geometries and optimised pump schedules. It embodies a twodimensional description of fluid flow in the fracture. Rapid fracture growth (e.g. through negative stress barriers) is handled in a stable manner.

Propagation through layers with different Young's moduli is described using the Barenblatt approach, giving a realistic estimate of containment by modulus contrasts: commercially available models generally overestimate the containment effect. This is of importance for the simulation of drill-cutting reinjection, where stiffness layering may enhance possible containment by soft, permeable sand layers interbedding the thick shales. The model can also handle the continuous stiffness gradient in these shales.

Benchmark comparison with data from the GRI staged field experiment No. 3 shows that the new model compares well with existing models for this case. The performance of the model is illustrated for three field cases. The first case concerns the design of a massive hydraulic fracturing treatment offshore The Netherlands, in a reservoir consisting of five layers with negative stress barriers. The simulator was used to optimise the perforation location and the pump schedule, using an expected net pressure at shut-in of 500 psi. The observed onset of tip screen-out at the end of the treatment suggests that the schedule as it was pumped away was indeed (nearly) optimum. The treatment produced an initial transient productivity improvement factor of about five.

The other two field cases are examples of different North Sea drill cuttings reinjection scenarios. The possible importance of stiffness layering between the thick shales and thin interbedding permeable sands when injecting large volumes (e.g. from a dedicated injection well) is highlighted. The simulator is used to assess the relative merits of intermittent injection with long shut-in intervals (one month) and continuous injection.
Successful Prediction of Condensate Wellbore Behaviour Using an EOS Generated from Black Oil Data
Authors: Furnival S. R. , Baillie J. M.
Published: December 2007

Few, if any, blackoil-type correlations are available for describing the PVT behaviour of Gas Condensates and Volatile Oils. Such near-critical fluids are generally modelled using multi-component Equations of State (EoS). However, EoS require detailed laboratory analyses to be performed on actual reservoir fluids. For modelling production wells, this data is often of poor quality or not available at all.

In a production system, there is usually a regular measurement of the post-separator condensate and gas gravities (stock tank oil and gas) and the total Condensate-Gas-Ratio (CGR). In this study, this data was used to generate a four pseudo-component description that was then used with a conventional EoS to make predictions of fluid behaviour.

The basis for the selection of the four pseudo-components is discussed as is the calculation of the component mole fractions using the two stock tank gravities, the CGR and the additional constraint of the mole fractions summing to unity.

The EoS model was tuned to data obtained from a North Sea Gas Condensate well. The tuned model was then used with an appropriate flow correlation to successfully predict top hole conditions, having specified measured bottom hole conditions.
Four Years' Subsea and Marine Experience With the Ivanhoe/Rob Roy Development
Authors: Smith S. N.
Published: December 2007

This paper presents experience of subsea and marine systems gained from the first four years of production from the Ivanhoe/Rob Roy fields focusing particularly on those areas which are different from a fixed platform development.

As an introduction the overall field layout is described and the success of the development is demonstrated by summarising availability of the facilities. The paper then describes the field development work since first oil, together with the inspection, repair and re-design work that have been necessary to ensure this success. The description includes work on all facilities on the sea bed, work on marine systems, and subsea well servicing. It thus includes the hull, stability and damage stability, bilge and ballast systems, subsea Christmas trees, moorings, flexible risers, flowlines and jumpers, valves, chokes, electro-hydraulic control system, umbilicals, downhole gauges, etc.

The information can be used to lead towards more cost effective developments in the future.
TAME: A New Concept in Water-Based Drilling Fluids for Shales
Authors: Downs J. D. , van Oort Eric , Redman D. I. , Ripley D. , Rothmann B.
Published: December 2007

There is a growing awareness in the drilling industry that many cases of borehole instability may be caused by the changes in shale pore pressure resulting from fluid invasion. A hydraulic pressure differential, arising when the mud-column pressure exceeds the pressure in the shale pore fluids, drives fluid from the wellbore into the surrounding shale and propagates an expanding pressure front. The resulting changes in the effective stresses around the wellbore may then be sufficient to promote rock failure.

A new generation of water-based drilling fluids are being designed to minimise such pressure-penetration effects in pores by reducing either the shale's permeability to aqueous fluids or the rate at which fluids can flow into shales. The new thermally activated mud emulsion (TAME) system, utilising a combination of a surfactant solution and emulsion phases to reduce fluid entry into shales, is one of the first field-tested drilling fluids designed specifically to reduce borehole instability arising from the penetration of pressure into shale pores.

The first prototype TAME system comprises a conventional aqueous KCl-polymer drilling fluid containing a solution of an alcohol alkoxylate additive, components of which can undergo a phase transformation at downhole temperatures to form a fine emulsion. Both the solution- and emulsion-phase elements of the alkoxylate appear to make some contribution towards reducing rates of fluid flow into shales, although their exact mode of action is still unclear.

The prototype TAME system has been successfully field tested during 1992/93 in 17.5", 12.25", 8.5" and 6" sections of five deviated development wells and one exploration well in the UK North Sea. The overall conclusion from this test campaign is that the TAME system is superior to conventional KCl-polymer and polyglycerol muds by virtue of its better borehole-stabilising qualities, higher rates of penetration, significant waste reduction and lower mud time rates (the total time spent drilling on bottom, tripping, conditioning the hole or mud and circulating the mud).

Following these encouraging field tests, TAME formulations have evolved to become Shell Expro's preferred fluid system for drilling reactive shales in standard exploration, appraisal and development wells. Moreover, building on the information obtained from field experience with TAME, even more effective shale drilling-fluid formulations are currently under development.
Maureen Produced Water Injection
Authors: King R. E.
Published: December 2007

This paper describes the application of produced water injection on the Maureen platform to improve the quality and reduce the quantity of water discharged overboard. The production history of the field is reviewed. A number of alternatives considered to resolve the problems associated with increased water production are discussed. Results of a produced water injection trial are presented, together with the performance to date of permanent injection facilities. Future plans are outlined for optimising water management requirements and reservoir pressure support.
Goal-Setting Regulation: Truly Cost-Effective Safety?
Authors: Perham A. J. , Garlick A. R. , Forster J. H.
Published: December 2007

This paper aims to support the Offshore Industry to achieve truly cost-effective safety. It examines the new framework for emerging Offshore Regulations, with its largely "goal setting" approach.

Three main themes are presented: how to understand the HSE's requirements for acceptable Safety Cases; professional project management planning, with "tit for purpose" quantitative risk assessment (QRA) and cost benefit analysis (CBA); and decision support for remedial action plans that are truly cost-effective and reduce risk demonstratably, as low as reasonably practicable (ALARP).

An affirmative answer is given to the question posed in the title, acknowledging the massive efforts being made. Momentum must be maintained and the safety cases put to work, using several recommended steps for future action.
The Ivanhoe/Rob Roy Safety Case Development
Authors: Spittal John
Published: December 2007

The development and submission of installation safety cases is an activity which has and will in the future utilise a significant level of operators' manpower. The Amerada Hess Ivanhoe/Rob Roy fields safety case was prepared and submitted initially to the HSE as an early voluntary submission for a floating production system and then as the formal safety case submission in June 1993.

This paper will detail how the safety case was developed starting from the ‘Forthwith Studies’ defined by the Cullen Report. It will detail the various development stages of the document and the changes that were carried out before a satisfactory format was reached. A particular strength identified in the voluntary safety case was the hazard identification and mitigation section, which also includes the hazard inventory. This section will be presented in detail with examples in some of the main hazard groups, namely (i) loss of containment, (ii) dropped object, (iii) marine impact and helicopter crash, (iv) marine system faults, (v) loss of structural integrity and (vi) environmental hazards. The methods used to firstly identify the hazards associated with the installation, then qualitatively risk rank and finally, perform quantified risk assessment will be presented. Detailed information on the dropped object studies will be specifically highlighted.

This paper will provide an insight into the development of a safety case which has been reviewed by the HSE, as part of the voluntary safety case exercise. The sharing of the Amerada Hess experience will be of great benefit to those involved in the development of installation safety cases, particularly in the area of floating production systems.
Horizontal Drilling with Coiled Tubing: A Look at Potential Application to North Sea Mature Fields in Light of Experience Onshore The Netherlands
Authors: Faure A. M. , Zijlker V. A. , van Elst Herman , van Melsen R. J.
Published: December 2007

Drilling with a continuous coiled string presents an array of opportunities for reducing drilling costs and improving production potential. It offers exciting perspectives for enhanced resource management in established oil and gas provinces.

A Shell operating company recently completed a horizontal sidetrack with coiled tubing onshore the Netherlands. A medium radius horizontal lateral was drilled with a 2-inch coiled tubing. This operation was the first step towards the development of a comprehensive Coiled Tubing Drilling (CTD) system able to re-enter and re-complete wells without conventional rig assistance.

Operations in the Netherlands provided key parameters for evaluation of the potential and limitations of CTD. This experience indicates that CTD is a suitable technology for the optimization of mature North Sea fields. It offers potential cost advantages and should help to maximize hydrocarbon recovery in this area.

New developments are required to meet the challenges of the offshore environment, under-balance operations, short-radius multiple drainholes or through tubing drilling to name but a few. Investments in these directions are well worth while, in view of the opportunities that CTD offers for enhancement of the drilling and production process.
A New Approach to Subsea Oilfield Development Using Innovative ESP Technology
Authors: Simpson A. J. , McKenzie Martin , Robertson M. P.
Published: December 2007

A family of exciting new Electric Submersible Pump (ESP) technologies promises to radically improve the development economics of many oilfields and field extensions. This technology is particularly relevant to prospects in the range 5-100 million barrels reserves, which are located greater than 15 kilometres from existing platforms and often suffer uncertainties on reservoir performance (pressure, sweep, heterogeneities inflow performance etc.). Prospects in that category generally offer mediocre to inadequate economics or unacceptable risks of ‘downside’ potential. Platform development entails untenable capex exposure, whereas conventional subsea development (e.g. by gas lift) will result in very inferior production performance.

The new technologies which ‘unlock’ the economics of such fields are:

Viable subsea ESP technology is available now and will be field proven during 1994/95. Proven high reliability pump systems are now available, underwritten by performance contract. Bottom discharge pump systems offer powered ‘dump’ injection from an aquifer to the oil zone. (This is a particularly efficient way of achieving water injection and obviates the tremendous weight penalty of conventional water injection systems). Tandem pump versions of both conventional and bottom discharge systems offer much higher performance and assure long system life. Multiple pump completions may offer the prospect of the cost effective ‘complete for life’ subsea ESP well in both conventional and bottom discharge mode.

These technologies offer superior technical and economic performance compared to existing, available methods, thus achieving enhanced development economics more robust to reservoir performance uncertainty.
Cost Reduction: Initiative for the New Era
Authors: Spaven P. M.
Published: December 2007

In order to meet the demands of cost-effective new field economics in the next decade, the Industry must generate a new strategy for smaller fields development. The CRINE initiative was first considered in the summer of 1992. This paper will highlight why the CRINE initiative was launched, the methodology being used to identify solutions, and what objectives were set.

Most cost reduction initiatives in the past have been single company activities designed to meet a corporate strategy plan. CRINE has taken a different approach in its use of work groups with selected members from all sectors of the industry. Dissension, self-criticism and team effort is being harnessed to generate new culture for the future. The CRINE Steering Group has set an initial objective of reducing 1992 capital costs by 1/3 within 2 years and by a further 1/3 within 5-7 years.
Modelling Blowout Control by Means of Downhole Kill Fluid Injection
Authors: Oudeman Pieter , Baaijens M. N. , Avest Dick ter
Published: December 2007

Blow-outs happen very infrequently nowadays, thanks to strict well-control procedures and improved drilling equipment. When they do occur, control over the well can usually be regained rapidly after capping. In certain cases, it may be necessary to kill the well after a blow-out by injecting kill fluid through a relief well. The simulator described in this report predicts the sequence of events during such operations. Study of the sensitivity of simulation results to variation of input parameters provides a basis for optimal design of relief wells and optimal choice of kill procedures.
Optimisation of the Return Gas Distribution During Kicks in Oil- and Water-Based Muds: Results From Full-Scale Kick Experiment
Authors: Rommetveit Rolv , Hovland Frank , Olsen T. L.
Published: December 2007

A number of gas kick experiments have been performed in a 2000 m long, 60° inclined research well. During the experiments a several of parameters were varied, such as mud density, mud type, gas concentration, and control rate of the kick. The well was heavily instrumented during the experiments, both downhole and surface.

The gas distribution at start of the kick has been computed, and compared to the gas distribution out of the well which was calculated based on, measurements of the mixture density through the choke line, choke pressure and pit gain. This was done for the majority of the 24 kicks which were performed. The effect of mud density and solubility on the return distribution has been analysed. Effects of operational procedures during the kicks have been analysed as well (circulation rates and duration of close-in).

The work shows that the return gas rate and gas distribution depends on the following variable; the initial gas distribution, mud type (OBM or WBM), and operational history of the kick.

Optimal operational control procedures which will create the most favourable return gas distribution are recommended.
A System Approach to Annular Control for Total Well Safety
Authors: Leismer Dwayne
Published: December 2007

In the event wellhead integrity is lost, the uncontrolled flow of hydrocarbons could risk life, property and the environment. To prevent this risk subsurface safety valves can be used to control the well below the wellhead. Conventional surface controlled subsurface safety valves (SCSSV) are used to control the production tubing. However, often the annular space between the tubing and casing contains large quantities of gas directly below the wellhead1. An annular control (AC) safety valve is a surface controlled subsurface safety valve which allows annular flow when open but provides a barrier below the wellhead when closed. When the AC safety valve is used with a conventional SCSSV it can provide overall well safety.

The scope of this paper is to identify, review the design and summarize testing of the components that comprise an annular control safety system.
The Development and Application of a Slickline Retrievable Bridge Plug
Authors: Gee Nicholas , Brown Sam , McHardy Colin
Published: December 2007

The development of through-tubing retrievable bridge plugs suitable for the monobore type completions favoured in the North Sea provides a clear example of completion manufacturers fulfilling a need created by Operating Company requirements.

The development and initial field application of a slickline retrievable bridge plug is described, illustrating the innovations inspired both by the Operating Companies technical leadership and the drive toward cost efficiency in well operations.
Everest and Lomond Completion Design Innovations Lower Completion and Workover Costs
Authors: Laing C. M. , Ogier M. J. , Hennington E. R.
Published: December 2007

The completion design and perforation operations for the Everest and Lomond gas condensate fields incorporated several significant innovative features. These resulted in reduced rig time requirements, quicker access to sales gas and lower operations costs. Future benefits will include better well performance and reduced well workover and repair costs.
Current Fiscal Problems in the UKCS
Authors: Kemp A. G.
Published: December 2007

The 1993 budget has dramatically changed the fiscal situation applied to petroleum exploitation in the UKCS. The changes substantially impact on all aspects of the upstream business.

On existing producing fields and those under development there is a marked positive effect on industry net cash flows from the reduction in the rate of Petroleum Revenue Tax (PRT) from 75% to 50%. On discoveries not yet developed the abolition of PRT does not change the effective tax take on production income on the majority of fields as the existing allowances already provide effective tax shelter. On the large fields the tax take can go down substantially. On the other hand the net of tax appraisal costs on new prospects increase fourfold.

The post-tax returns on incremental investments in mature fields are increased significantly by the reduction in the PRT rate.

The removal of the PRT crossfield allowance for exploration and appraisal clearly has an adverse effect on exploration incentives, but the fiscal situation facing an explorer is now very simple, and the level of tax take very low by international standards.

The imposition of the Gas Levy and PRT on new gas contracts or on incremental investments in mature gas fields can readily render such projects non-viable. The precise impact of PRT depends critically on what PRT volume allowance is available for the project in question.
The New Offshore Health and Safety Regulations: A Legal Overview
Authors: Sprague C. W.
Published: December 2007

The investigation into the causes of the explosion on the Piper Alpha Platform on the 6th July 1988 exposed serious shortcomings in the British offshore safety regime. In particular, the capacity of the inspectors employed by the Department of Energy's Petroleum Engineering Department to ensure compliance of offshore installations with statutory safety requirements was found to be wholly inadequate.

The safety case procedure recommended by Lord Cullen in the report following his Enquiry, and implemented in the Offshore Installations (Safety Case) Regulations 1992, represents a wholly different approach to the question of safety on offshore installations. The onus of ensuring that their installations are designed and operated safely and in compliance with the relevant statutory requirements is placed upon the operators themselves. They have, by way of detailed safety cases, to satisfy the Health and Safety Executive that they are meeting these requirements. The Regulations also impose upon operators continuing obligations to comply with the safety cases that they have submitted, to alter them so as to reflect changes in their operations and to submit revised safety cases every three years. Acceptance of a safety case by the Health and Safety Executive and the operator's subsequent compliance with it are pre-requisites of his being allowed to continue with his operations.
Managing Exploration Activities in Environmentally Sensitive Inshore Waters
Authors: Kearns John , Parker J. G.
Published: December 2007

In the recent second stage of the 14th Offshore Licensing Round, a number of blocks have been awarded in areas of high environmental sensitivity. At the same time the current economic climate is providing operators with new challenges for cost control. Both these factors can produce conflicts unless operators have a clear strategy for managing exploration activities in environmentally sensitive areas.

Over the last 3 years, Hamilton Oil Company Ltd has carried out seismic operations and has drilled a number of exploration and appraisal wells in environmentally sensitive areas off the North Wales and North West of England coasts. Over this period the company has developed an approach to planning and executing these activities which takes into account environmental factors without incurring excessive exploration costs.

This paper describes how this approach has been developed and provides a template for similar operations in other environmentally sensitive areas.
The VARI FLO™ Motor: A New Mud Motor Concept, its Design, Development and Applications
Authors: Susman Hector
Published: December 2007

The VARI FLO™ Motor was developed to provide the industry with a downhole motor to meet the ever increasing demands of today's drilling requirements

It is recognised that there is a requirement for a source of downhole motor power, which suffers less from the effects of heat and modem corrosive drilling fluids, whilst simultaneously offering a shorter motor for directional drilling applications.

Our Motor is a Vane type, positive displacement motor, built without the use of rubber in the working parts.

The construction of vane or in our case roller type motors are as the Moyneau motor, simple devices. However due to the somewhat ‘interfering’ fit between rotor and stator, Moyneau motors are somewhat difficult to take apart in particular when one also takes the greater length and weight into account.

The motor assembly is the only part which is conceptually different from present motor designs and you will find a diagram attached to this paper. (Figure 1)
Enhancing Safety and Efficiency While Running Casing With Top/Side Drives
Authors: Fulks R. W. , LaFleur K. K.
Published: December 2007

When casing is run into a wellbore problems may be encountered that require immediate circulation through the casing. A new method to quickly and safely achieve circulation through the casing will be discussed along with field performance data.
Reservoir Management in a Marginal North Sea Cluster Development
Authors: Dominic P. R.
Published: December 2007

The Gannet cluster is an integrated oil and gas development encompassing the Gannet A, B, C and D fields which came on-stream in October 1992. This marginal field development marks an evolutionary phase for Shell U.K Exploration and Production as future fixed installation green field developments are expected to consist of small sized hydrocarbon accumulations which will be uneconomic to develop on their own The features which serve to make this otherwise marginal development economic pose considerable reservoir management challenges over the life of the project because of the differing reservoir conditions, expensive data acquisition in sub-sea wells, the integrated nature of the facilities and the need to meet stringent sales gas contractual requirements whilst maximising oil production This paper describes the pre-drilling optimisation studies that were carried out, the success of which is partly attributable to the introduction of integrated field teams within Shell Expro's Central Fields Unit, and the preparation of a reservoir management plan which is now an integral part of the planning process for the Gannet Cluster.