bluuebunny/crossref_metadata_2025 huggingface dataset:
Delineation of Hydrodynamic/Geodynamic Trapped Oil in Low Permeability Chalk
Authors: Jacobsen Nils L. , Engstrøm Finn , Uldall A. , Petersen Niels W.
Published: December 2007

The present paper describes the basis for delineating a significant volume of non-structurally trapped oil within low permeable chalk at the flank of the mature Dan field offshore Denmark. Drilling of extensive long horizontal wells at the flank of the main field, including one that set a world record horizontal section, has resulted in the discovery of a thin high porous (>30%) Maastrichtian chalk unit. The best reservoir zone is developed with consistent high oil saturation in the order of 80-90%, and trapped between lower porosity predominantly water bearing Danian and Maastrichtian Chalk units.

Full vertical and lateral pressure continuity is observed between the hydrocarbon and water bearing units on the main field. It was therefore surprising to find the oil in the better of the units extending down flank, and outside the structural closure far beyond what could be predicted from modeling of the saturation profiles observed in the crestal wells. Drilling of three wells with up to 19,600 ft long horizontal sections in the flank area, consistently found the free water level dipping and deepening significantly to the north-west of the field allowing hydrocarbon filling of the units of highest reservoir quality in this area.

Drilling of long reach horizontal wells thus provided the data needed for regional mapping of the free water level required as input to fluid modeling. Information on layer thickness and matrix porosity, necessary for volumetric calculations, was provided from well logs and through stochastic forward modeling of seismic acoustic impedance data extracted from a regional 3D survey.

Improved understanding of the hydro- and geodynamic induced fluid pattern, combined with seismic mapping and modeling, thus resulted in the identification of significant and yet un-drained volumes at the flanks of a mature oil field.
Comprehensive Mechanistic Modeling of Two-Phase Flow in Deviated Wells
Authors: Kaya A. S. , Sarica C. , Brill J. P.
Published: December 2007

A new comprehensive mechanistic model was developed to predict flow pattern and flow characteristics such as pressure drop and liquid holdup in vertical and deviated wells. The model includes five flow patterns: bubbly, dispersed bubble, slug, churn and annular flows.

Flow pattern prediction incorporates the transition models proposed by Barnea1 (or Taitel et al.2) for dispersed bubble flow, Ansari et al.3 for annular flow, Tengesdal et al.4 for churn flow, and a new bubbly flow transition model. For each predicted flow pattern, a separate hydrodynamic mechanistic model is proposed. A new hydrodynamic model for bubbly flow has been developed, and the Chokshi5 slug flow model has been modified significantly. The Tengesdal et al. and Ansari et al. models have been adopted for churn and annular flows, respectively.

The comprehensive model is evaluated using a well databank of 2,052 cases covering a broad range of field data. Pressure drop predictions with the model are also compared with those using the Ansari et al., Chokshi, Hasan and Kabir6, and Tengesdal mechanistic models, and the Aziz et al.8, and Hagedorn and Brown9 correlations. The results of the comparison study show that the proposed comprehensive mechanistic model performs the best and agrees with the data.
Acid Stimulation of Power Water Injectors and Saltwater Disposal Wells in a Carbonate Reservoir in Saudi Arabia: Laboratory Testing and Field Results
Authors: Mohamed S. K. , Nasr-El-Din H. A. , Al-Furaidan Y. A.
Published: December 2007

Seawater power injectors and saltwater disposal wells are used to maintain reservoir pressure in a carbonate reservoir in Saudi Arabia. Various forms of hydrochloric acid were used to stimulate damaged wells and restore the injectivity of these wells. The forms of the acid used were regular, emulsified, and in-situ gelled acids. Acid diversion was achieved by using a coiled tubing unit, nitrogen foam, in-situ gelation, emulsified acid or combinations of these methods.

A comprehensive investigation was undertaken to assess the effectiveness of acid treatments performed in the field and improve the outcome of the acid jobs. Laboratory and field investigations were conducted simultaneously to address formation damage and associated problems. These investigations included coreflood tests to screen various acid formulae, and analysis of field samples to identify the damaging mechanism.

More than 80 acid jobs were analyzed in this study. A new empirical coefficient was identified and used to evaluate these jobs. The coefficient was based on: 1) the ratio between the pre and post acid injectivity indices, 2) the rate of decline of normalized well injectivity index, and 3) the incremental cumulative injection from the Hall plot following the acid job and before the first change in the slope. In addition, chemical analysis of acid returns (spent acid) was used to assess the damaging mechanisms and determine the type and concentration of various acid additives.

Improper use of emulsified acid and in-situ gelled acid was found to result in poor field results. The outcome of acid jobs was found to be a function of the volume ratio of regular to in-situ gelled acid. Good field results were obtained when the volume of in-situ gelled acid was 15-30% of that of the regular acid (15 wt% HCl). Furthermore, the study confirmed that acid injection using coiled tubing enhanced the efficiency of the acid treatment.

This paper highlights the importance of conducting laboratory and field evaluation of acidizing treatments. The following new findings were obtained:

A new job index was developed and used to assess acid treatments in the field. Severe formation damage can result from the improper use of in-situ gelled acids. Analysis of spent acid was effectively used to optimize the concentration and type of various acid additives.
Design Approach to Sealant Selection for the Life of the Well
Authors: Bosma Martin , Ravi Kris , Driel Willem van , Schreppers Gerd Jan
Published: December 2007

Recent experience in the field has demonstrated that the mechanical properties of the annular sealant are a critical factor in the success of a well. A demanding operational regime such as High Pressure/High Temperature (HP/HT) and well interventions, e.g. pressure testing stimulation, place high demands on the mechanical design of a candidate sealant.

The following steps should be followed to determine the required mechanical properties of such well sealant candidates:

The stability of the bore hole should be evaluated prior to placing the sealant in the annulus. The stability is affected by the far field stresses, the weight (s.g.) of the drilling fluid and the mechanical properties of the formation. The integrity of the sealant should be investigated for the

operational envelope of the well. Finite Element models were used to determine the influence of wellbore stability aspects and the effects of loading on the integrity of the sealant. The mechanical properties of the sealant considered were elasticity, tensile strength, shear strength and bonding strength. In this way it was possible to examine aspects of non-linear material behavior of the sealant.

The following factors were investigated in this study:

What are the well parameters and its operating envelope? What are the total stresses on the formation and on the sealant under various HP/HT conditions? Which mechanical properties does the sealant have to possess in order to be able to withstand different types of stress?

The study indicated that there is a strong interaction between on the one hand the behavior of the sealant and on the other hand the formation in-situ stresses, the formation properties, the well completion parameters and its operating envelope. Depending on these input conditions, the sealant was observed to behave in one of the following manners.

The sealant remained intact without any damage. A micro annulus occurred between sealant and casing/formation. The sealant failed because of either tensile or shear deformation.

Calculations were performed for various wellbore stability scenarios, well completion characteristics, well loading envelopes and properties of the sealant. Typical oil well cement slurries, latex slurries, foam cements and cement hybrids were investigated. Typical results from the study are discussed and procedures for field application are given.
An Integrated Solution of Extended-Reach Drilling Problems in the Niakuk Field, Alaska: Part I - Wellbore Stability Assessment
Authors: Dowson S. L. , Willson S. M. , Wolfson L. , Ramos G. G. , Tare U. A.
Published: December 2007

The Extended Reach Drilling (ERD) program in the Niakuk Field, North Slope, Alaska was suspended in January 1998 due to hole problems in the 8.5" sections of two ERD wells. An integrated wellbore stability study was undertaken to identify and address the problems. The work undertaken involved detailed characterisation of the troublesome shales and calculation of mud weights required for acceptable hole quality and well stability.

This paper shows how instability in the two suspended wells was attributed to both compressive and tensile failure of the shale formations. The primary cause of well failures was drilling with too low a static mud weight, typically 0.5 ppg lower than recommended for acceptable hole quality. In addition, the wells used a viscous mud, possessing a high Equivalent Circulating Density (ECD) relative to its static mud weight. This resulted in a time-dependent, fatigue-induced extension mode of borehole instability. This mode of failure is not common but is highlighted as a mechanism requiring attention in ERD well planning.

The paper documents the back analysis of well failures, synthesis of geological information, the analysis approach adopted for assessing chemical and mechanical instability, and a forecast of required mud weights for future ERD wells. The paper then presents a summary of subsequent well drilling case histories which show improvements in hole quality due to decreased instability. This resulted in a reduction of non-productive time and large cost savings to the business. In particular, one of the suspended 8.5" hole sections has now been side-tracked with negligible hole enlargement over a 5730ft section through previously troublesome shales.

In conclusion the paper emphasises the need for a proper wellbore stability assessment prior to drilling challenging ERD wells.
Full field pressure simulations using a very accurate, yet inexpensive well model
Authors: Baumann C.E. , Price H.S. , Reddy M.P. , Thuren J.B.
Published: December 2007

The technique presented in this paper is aimed at solving the pressure equation in oil reservoir models containing a large number of wells. This technique is applicable to heterogeneous reservoirs and does not require computational meshes that conform to the wells. Typically, several perforated wells may appear within a single computational element (grid block), and horizontal/deviated wells are simulated with the same methodology as vertical wells.

The numerical technique used to simulate near-wellbore flows is a special form of the generalized finite element method with special basis functions. No productivity index or any other approximation is used; the near-wellbore pressure is modeled by the use of special basis functions. This technique is very accurate yet inexpensive, because higher accuracy is obtained without resorting to fine grids around wells. For this reason, this technique is very well suited to simulate wells that are turned on/off frequently. When wells come online or are shut off, the wells are automatically added/removed from the model. This translates in net saving at no cost, because this technique does not incur in the extra cost of having a fine mesh where is not needed.
Analysis of Stuck Pipe in Deviated Boreholes
Authors: Aadnøy Bernt S. , Larsen Kenneth , Berg Per C.
Published: December 2007

The complexity of the wells haveincreased significantly inlater years. Reach has more than doubled, and highinclination and fully 3-D well paths are common. However, statistics shows that sidetracking the boreholes due to stuckpipe has also shown a significant increase, and is presently ahigh cost factor. The margins between success and failure arenow much smaller.

A larger study was initiated to understand the stuck pipesituation better, and to develop improved procedures. Amechanistic approach was chosen. The following elementswere analyzed: 1) the forces developed during differentialsticking, 2) pipe strength under combined loads; tension, torque and pressure, 3) effects of buoyancy under variousconditions like equal or different mud densities in drillpipeand annulus, 4) wellbore friction as related to torque and drag.

This paper presents new equations to determine depth to thestuck point in deviated wellbores, based on pulling tests andtorsion tests. In particular it is shown that bends in thewellbore leads to more friction, which with the new equationsresults in a deeper stuck point in a deviated well compared to asimilar vertical well. Knowing all the forces involved in astuck pipe case, another analysis was performed to determinethe action that has largest impact to free the pipe. One of themain conclusions is that the most important element to freethe string is to keep the bottomhole pressure as low aspossible. The paper will present three methods to free thepipe, which where developed from the analysis: 1) maximummechanical force method, 2) minimum density method, and 3)maximum buoyancy method. A detailed field case from theYme field in the North Sea will demonstrate these methods, and show the effect on the stuck point using each method.

In addition to the field case, the paper will in the Appendicespresent the complete equations for pipe stress and strengthunder 3-dimensional loading, and define the effects ofbuoyancy in deviated wellbores. In particular is the buoyancyissue resolved, showing the differences and similaritiesbetween "the piston force approach" and the law ofArchimedes, as applied to deviated wellbores.
Rheology of Various Drilling Fluid Systems Under Deepwater Drilling Conditions and the Importance of Accurate Predictions of Downhole Fluid Hydraulics
Authors: Davison J. M. , Clary S. , Saasen A. , Allouche M. , Bodin D. , Nguyen V-A.
Published: December 2007

Previous rheological studies of water-base and oil-base muds have concentrated on fluid viscosities at elevated temperatures and pressures. This paper extends the data available to cold temperature regimes which can be expected to occur in the riser for deepwater wells. The rheology of eighteen different drilling fluids covering WBM, OBM and SBM have been evaluated between -1° to 90°C and 1 to 344.7 bar. The Herschel-Bulkley and Casson models both fitted the OBM and SBM rheograms very well. For the different WBM systems, the Herschel-Bulkley model also fitted the salt/polymer fluids and unweighted bentonite-based fluid rheologies, however, the Casson model best described the weighted bentonite-based fluid rheologies. The effect of the cold fluid viscosity in the riser on ECD for deepwater wells was assessed using a software model which uses a transient temperature simulator in conjunction with a hydraulic model which accounts for different mud viscosity throughout the wellbore. Comparing the ECD predictions with those calculated where the mud rheology is independent of temperature and pressure, the ECD was found to be underestimated by up to 6.1% for a SBM and overestimated by 3.1% for a WBM. If there are formations with small differences in the fracture and pore pressure gradients, then these variations in ECD could cause well control problems.
Cleanup of Wall-Building Filter Cakes
Authors: Zain Zulkeffeli M. , Sharma Mukul M.
Published: December 2007

Building up external filter cakes during drilling and completion operations has long been one of the most practical ways to minimize fluid loss to the formation. The effectiveness of the filter cake is critical especially for long openhole completions with no perforations. It is usually assumed that this wall-building material will be removed during oil production, due to pressure drawdown. However, it is quite commonly observed that only a small fraction of the cake is removed, leaving large portions of it remaining on the formation face. This condition results in a small wellbore area open to flow and a large skin. To increase the flow area and minimize skin, the filter cake needs to be completely removed. Solids from filter cakes can also cause plugging of screens and gravel packs. This is particularly important in horizontal wells completed openhole.

Experimental results are reported for mud cake lift-off tests. The flow initiation pressures required to flow through or remove drilling and completion fluids filter cakes are measured together with the return permeability of the rock. In this study, sized CaCO3 and sized salt drill-in mud were tested on rock samples with permeability ranges between 3 to 2000 md. The effects of mud filtration pressure, rock permeability, and flow back rate were also investigated. The results show that sized CaCO3 fluids require lower flow initiation pressures and are less damaging than sized salt fluids. Despite having low mud filtrate volume and less internal damage, low permeability samples need relatively high flow initiation pressures compared to high permeability samples. Total mud cake removal is observed for experiments with limestone cores while only cracks and small holes were seen for experiments with sandstones. This observation suggests that cake removal is not just a function of permeability but depends on mineralogy as well. High overbalance pressures were also found to increase the magnitude of the flow initiation pressure.
Methodology for Variogram Interpretation and Modeling for Improved Reservoir Characterization
Authors: Gringarten E. , Deutsch C. V.
Published: December 2007

The variogram is a critical input to geostatistical studies. It is the most widely used tool to investigate and model spatial variability of lithofacies, porosity, and other petrophysical properties. In addition, 90% of geostatistical reservoir characterization studies use variogram-based geostatistical modeling methods. Furthermore, the variogram reflects our understanding of the geometry and continuity of reservoir properties and can have an important effect on predicted flow behavior and consequent reservoir management decisions. Yet, the practice of variogram interpretation and modeling is poorly documented and unexperienced practitioners find themselves at lost when required to provide a reliable variogram model. This often results in wrong variogram models used in subsequent geostatistical studies.

Our approach is a two-step procedure similar to that used in modern well test interpretation, that is, model identification followed by parameter estimation. The total variance of the phenomenon under study is divided into variance regions. The behavior of each variance region is shown to follow clearly defined behaviors reflecting well-understood geological features. Establishing a mathematically consistent and geologically interpretable variogram model is straightforward after model recognition.

The proposed methodology for variogram interpretation and modeling provides a better, more rigorous, quantification of spatial variability, which leads to improved flow models and management decisions. The theoretical background of our methodology will be presented. A number of case studies are then shown to illustrate the practical importance of the methodology.
Accuracy Prediction for Directional MWD
Authors: Williamson Hugh S.
Published: December 2007

This paper describes a new method for predicting wellbore position uncertainty which responds to the current needs of the Industry. An error model applicable to a basic directional MWD service is presented and used for illustration. As far as possible within the limitations of space, the paper is a self-contained reference work, including all the necessary information to develop and test a software implementation of the method.

The paper is the product of a collaboration between the many companies and individuals cited in the text.
Modelling of Gel Diverter Placement in Horizontal Wells
Authors: Menzies N. A. , Mackay E. J. , Sorbie K. S.
Published: December 2007

Optimum placement of injected fluids during scale inhibitor or acid stimulation treatments is often difficult to achieve in long horizontal or deviated wells. Crossflow effects that displace the injected fluids away from the target zone can exacerbate the problem, even when coiled tubing is used to deliver the chemicals to the desired location. To overcome these problems, diversion techniques, using waxes or polymer cross-linked gels, can lead to improved placement with little detrimental impact on post treatment production.

Placement of the diverter itself is not always simple, particularly for gels where the rheology is controlled by temperature and shear rates. Modelling techniques are being developed to assist engineers to design the various stages of these diverter treatments. The model described here was developed, using a commercial reservoir simulation code, to simulate the placement of polymer gels in high crossflow wells. The model parameters were based on a field inhibitor squeeze treatment performed on a 2,000 ft highly deviated well that (cross) flowed 3,500 bbls/day during shut-in. The effect of the crossflow during the various injection and shut-in stages of the squeeze treatment would be to displace the inhibitor away from the water producing zones, hence leaving these sections of the well unprotected. Accurate placement of the gel would prevent loss of inhibitor to the thief zones, ensuring protection for the intervals vulnerable to scale, and thus extending the time before the well would need to be re-squeezed.

The initial gel placement model demonstrated the interaction between viscosity, friction and transmissibility profile along the well at various injection and crossflow rates. A threshold viscosity was identified above which the injectivity profile was dominated by connection transmissibility factors rather than the friction and crossflow forces. The model was then developed to incorporate the effect on the gel viscosity of varying shear stresses along the wellbore and in the formation.

Development of a model that can predict gel placement enables optimisation of the diverter stage of a treatment. It also leads to more accurate modelling of subsequent chemical injection (eg. inhibitor or acid), and hence the benefit to squeeze lifetime resulting from the placement strategy can be assessed.
Screen Performance and Cleanup Characterization in Horizontal Well Drill-in-Fluids Using a Large-Scale Radial Flow-Cell
Authors: Asadi Mahmoud , Penny Glenn S.
Published: December 2007

A large-scale radial flow cell was utilized to characterize 0.004 in. gauge, 0.006 in. gauge, and 0.008 in. gauge 40/60 resin coated prepack screens based on retention testing. In addition, screen cleanup methods such as backflow (flowing water in the injection and production directions), 10% hydrochloric acidization at 120°F, enzyme soaking, and the use of breaker were evaluated on damaged screens. A carbonate drill-in-fluid (DIF) containing 5000 and 10,000 PPM solids was formulated and pumped for three hours at 16 gpm and 120°F into the flow cell and around the screen at a constant 60 psi differential pressure across the screen. Effluent samples of drill-in-fluid were collected to measure total solids. Removal efficiency of each screen was then calculated. Damaged screens were then subjected to one or a combination of various cleanup methods. Permeability of the treated screen was measured to 10-ppg NaCl brine solution and was compared to the screen's original permeability. The degree of plugging was evaluated based on the retained permeability of each screen after being subjected to one of the cleanup methods.
Geostatistical Scaling Laws Applied to Core and Log Data
Authors: Frykman P. , Deutsch C. V.
Published: December 2007

Reconciling data from different scales is a longstanding problem in reservoir characterization. Data from core plugs, well logs of different types, and seismic data must all be accounted for in the construction of a geostatistical reservoir model. These data are at vastly different scales and it is inappropriate to ignore the scale difference when constructing a geostatistical model.

Geostatistical scaling laws were devised in the 1960s and 1970s primarily in the mining industry where the concern was mineral grades in selective mining unit (SMU) blocks of different sizes. These principles can be extended to address problems of core, log and seismic data. The adoption of these classic volume-variance or scaling relationships presents some challenges. Some specific concerns are (1) the ill-defined volume of measurement, (2) uncertainty in the small-scale variogram structure, and (3) non-linear averaging of many responses including acoustic properties and permeability.

We demonstrate the application of volume-variance relations for upscaling and downscaling techniques to integrate data of different scales. Practical concerns are addressed with data from a chalk reservoir in the Danish North Sea. A direct sequential simulation algorithm accounting for data at all scales is documented.
A New Approach to Production: The Elgin & Franklin Partnership Based Operation
Authors: Menou G. , Hearn P. N.
Published: December 2007

Elgin and Franklin fields will be operated by Elf Exploration UK plc (EEUK) in an environment quite different from earlier generations of North Sea developments. Production personnel are becoming increasingly exposed to fluctuating commercial pressures in the oil & gas industry and need to be prepared to respond to these. At the same time, more and more Operators consider some functions which are important to successful production as ‘non-core’ activities and look to contractors to provide and support these functions through contracts which motivate performance.

Not only are skills transferring between Operators and contractors but also technology is being employed to reduce the size of offshore crews. In addition, production from Elgin and Franklin will commence under a goal setting legislative regime, which increases pressure upon Operators to ensure that they have access to the right people to ensure safe and responsible operation.

In an environment where competition for people with the right mix of knowledge, experience and adaptability is strong, EEUK has adopted a strategy for operation and maintenance of Elgin and Franklin which will enable contractors to demonstrate their commitment to new ways of working. Some companies that have supplied critical equipment and systems, have been given the opportunity to be involved long term in the successful and safe production of gas and condensate.

This paper discusses how EEUK has considered the risks of trends in contracting strategy, which are relatively new to them as a company, and balanced these risks against benefits of new ways of working. Through development of a suite of contracts to support operation and maintenance of Elgin and Franklin, EEUK has recognised the need to obtain services from the most appropriate source. Performance measures and incentives, which are being established, take account of the responsibilities and commercial considerations of both EEUK and its contractors.

The paper concludes with a summary of lessons learned so far in implementing a strategy that requires EEUK to manage some complex contractual relationships when Elgin and Franklin enters its Production Phase in year 2000.
Design, Material and Installation Considerations for Ultra Deepwater Pipelines
Authors: McKinnon Colin
Published: December 2007

This paper discusses specific considerations and challenges associated with the design and installation of subsea pipelines in deep water with reference to recent relevant projects. Such considerations include mechanical design, construction techniques and parameters, as well as prevailing physical and environmental conditions. On-going developments and design approaches are discussed together with existing installation capabilities and a review of possible future developments.
Design of a Deepwater / Deephole Dynamically Positioned Semisubmersible Drilling Unit with a Purpose-Designed Column Configuration
Authors: Haavie T. , Stakkeland H. , Florvaag M.
Published: December 2007

Tensions, derrick and rig equipment weights generally act near the centre of semisubmersible drilling units. Deepwater/ Deephole drilling operations in 1,000 - 3,000 metres water depth and up to 12,000 metres hole depth, also require more tubular storage capacity on deck than work in water depths up to, say, 200-500 metres and hole depths up to for example 7000 metres.

The four inclined centre columns on the FE-P099 semisubmersible represent steel applied directly in the paths of the major global forces resulting from such centrally acting loads. Two additional functions of these comparatively large diameter columns, are as providers of major storage space for powder tanks and as significant hydrostatic stability contributors, which strengthen the total steel application advantage of the FE-P099 over other traditional units with vertical columns and small diameter bracing supports.

The application of steel in the right places and for more than a single purpose leads, in turn, to a lower steel weight, a lower lightship weight, smaller displacement, less required thruster power, a smaller total power plant and a lower price than for other vessels advocating similar deck load capacity and dynamic station keeping capability.
Progress Towards Zero Based Hook-up
Authors: Hume Ian
Published: December 2007

The paper sets out to chart the step change continuous improvements achieved in UKCS Hook-ups from 1992 through 1998. This process has seen the manhours/tonne required to Hook-up and Commission large (greater than 20,000 te topsides) offshore installation fall from an industry average of 75 manhours/tonne to less than 15 manhours/tonne (Fig. 1).

The change process has been complex and it has been necessary not only to challenge the technical sacred cows but also the philosophical, cultural and organisational core beliefs prevalent in our industry during this period.

The story is not complete yet. We believe that there are still significant activity level reductions to be delivered some of which we have already targeted and no doubt we or others will deliver yet more.
Primary Separation and New Generation of Interface Level Measurement Systems
Authors: Yang M , Hall A R W
Published: December 2007

There are a number of new technologies that have been developed for the purpose of monitoring the interface level, the thickness of emulsion and foam layers simultaneously. These include capacitance based using embedded sensors; ultrasonic based with two transducers operating in pulse-echo mode; and devices based on measuring the variations in fluids heat transport; as well as nucleonic with which a number of ways have been configured specifically for the application of subsea separation systems.

Most of these techniques are being currently commercialised. This paper is therefore to review the state of the art of these instruments and that in general of the interface level measurement systems for separators; and to examine the pros and cons for their applications to the industry.
Step Change in Drilling Efficiency in Mature North Sea Fields from New Motor and Bit Drilling System
Authors: Gaynor T. M. , Irvine G. T. , Boulton R. , Gilchrist D. A. , Lane Ian
Published: December 2007

The paper describes the improvement in drilling efficiency obtained in five mature North Sea fields, by using a systems approach. The drilling program was managed by a drilling efficiency group consisting of a service company, drilling contractor and operator engineers drawn from several disciplines. All of the well sections were geometrically complex. Data was gathered using downhole pressure and vibration sensors, and acoustic caliper sensors.

MWD annular pressure measurements had shown that conventional steerable motor/bit combinations required extensive circulation and occasional back reaming to ensure adequate hole cleaning. MWD vibration measurements and BHA modeling had proved that particularly high levels of vibration were caused by both circulating and back reaming. This was directly associated with MWD, motor and other downhole tool failures. It was concluded that the basic problem was hole quality and attention was directed to eliminating hole spiraling deduced from MWD logs and calipers.

A new combination of compatible steerable PDM and long gauge bit was designed with input from the operator. This was designed to achieve improved hole quality from long gauge bits without losing the rapid deviation response of conventional motor/bit combinations. The aim was to improve overall drilling system efficiency, particularly poor hole cleaning, excessive torque and drag, and slow ROP when sliding.

The paper discusses the initial data gathering and diagnosis and how measurement and modeling of downhole conditions led to the optimal solution. Comparison between 8 conventionally drilled hole sections and 8 hole sections drilled utilising the new drilling system showed more than 50% reduction in overall drilling time. Significant time savings have been made when drilling in the orientated mode. Other benefits are reduced drilling WOB from 30,000 lb to 3,000 lb, reduced drilling torque and drag, and an overall improvement in hole quality reflected by improved hole cleaning.
Coiled Tubing NDT Inspection: Implementation, Experience and Results
Authors: MacArthur J. , Shearer C. , Crabtree A. , Nelson R.
Published: December 2007

The use of Coiled Tubing in the workover and drilling sectors of the industry has seen considerable growth. This is due, in no small part, to the changes in tubing manufacturing techniques that have led to better materials and more consistent tubing performance. Consistency of tubing performance has enabled a large body of research work to be conducted in order to understand the low cycle fatigue and mechanical behaviour of coiled tubing in service.

When Coiled Tubing (CT) is used in oilfield applications it is subject to numerous plastic bending reversals which impose low cycle fatigue damage on the tubing. This damage is cumulative and leads to eventual failure - loss of pressure integrity and in some cases catastrophic failure. With the research work undertaken over the last several years the boundaries of the operating envelope have been better identified and can be predicted with the use of fatigue management computer models.

A result of this knowledge is that, as fatigue failure can be predicted for a given tubing and tubing material, other factors are becoming influential in some of the premature failures experienced in field operations. These factors are often found to be such things as manufacturing flaws, corrosion and mechanical damage.

To further enhance the reliability of CT in service it would be beneficial to detect such flaws before the tubing is run into a well when the cost of tubing failure can be expensive. Several non-destructive inspection (NDT) devices are becoming available on the market, each with their advantages and disadvantages. This paper summarises experience gained in the Canadian Oilfield by application of current NDT technology over the last 24 months and what alterations have been made to operating procedures as a result.
Added Value from NMR Measurements to Characterize Gas Reservoirs in the U.K. Southern North Sea
Authors: Epping W. J. , Eggenkamp I. M. , Reid I.
Published: December 2007

In our Southern North Sea gas reservoirs, we have acquired a number of Nuclear Magnetic Resonance (NMR) logs under various conditions. Nuclear magnetic resonance tools respond primarily to the fluids present in the reservoir. Objectives of NMR logging are: to improve permeability estimation in noncored wells and to quantify fluid volumes. In several wells the log interpretation was calibrated by NMR laboratory analysis on core. We interpreted NMR logs in-house using advanced tools developed by Shell.

The application of NMR logs in low to moderate quality gas reservoirs is widely regarded as challenging. Reasons for this are the low NMR signature of gas due to the combined effect of low porosity and a low hydrogen index.

Key findings of our work are:

If properly used, NMR tools confirm the interpretation by conventional tools and improve on permeability and fluid estimation. Some of our logging jobs could have provided more information with better planning (of acquisition parameters, tools and mud systems) and more experience available. Porosity and permeability by NMR are less dependent on core calibration than conventional derivation from porosity tools. Our in-house interpretation increased accuracy and insight into the reservoir.

In this contribution, we will report our experiences with NMR logging and interpretation and comment on the added value of NMR logging in lower quality gas reservoirs.
Optimising the Reservoir Management of Remote, Subsea Fields
Authors: Storer A. J. , Kelly R. T. , Fleming J. M.
Published: December 2007

As a result of field development in increasing water depth, technological advances and general project economics, subsea-developed accumulations are becoming more remote from the host infrastructure; furthermore, these accumulations are getting larger. This raises several problems for those concerned with longer term reservoir management of such fields, including limited well testing opportunities. The case study of a subsea development of several hundred Bcf of gas at a distance of 50 km from the host, offshore South Africa, demonstrates how through alliancing the reservoir and surface evaluation efforts, the conflicting strategies of maximising reservoir management data and minimising cost may be balanced.
Multilateral Well Utilization on the Increase
Authors: Vullinghs P. , Dech J. A.
Published: December 2007

Shell U.K. Exploration and Production (Shell Expro), in its effort to reduce the cost per barrel of oil, continues to foster the evolution and utilization of multilateral wells and associated new technologies to develop, both, new and maturing reservoirs in all sectors of the North Sea.

Multilaterals with TAML junction levels 1 through 4 have been applied in six fields to date and will be applied to an additional seven fields within the next two years. Multilateral wells have provided a means to optimize slot usage, commercially develop lower-quality reserves within the Brent sequence, and combine appraisal objectives with economical development targets.

This paper will show how Shell Expro has applied multilateral wells in field development using level 1 and 2 junctions in the Southern Gas Basin in the Southern North Sea and level 4 junctions in the Central and Northern Sectors. The complementary technologies of underbalanced drilling and intelligent well completions are being integrated to optimize field development.

Shell Expro is also a major proponent of the level 6 multilateral (sealed junction) that is being developed by the industry.

With the increasing maturity of the North Sea reservoirs, the need to produce new oil cheaper and quicker, and the instability of oil prices, multilateral well technology provides the industry with another tool to lower the cost of reserve development.
Energy Optimization on Offshore Installations with Emphasis on Offshore Combined Cycle Plants
Authors: Kloster P.
Published: December 2007

Increasing fuel cost and concern regarding emissions have incurred focus on energy conservation on offshore oil and gas installations. On the Norwegian continental shelf there has been an increased commercial value of natural gas and a CO2-tax on fuel consumption the last 10 years. For the time being the alternative value of natural gas is in the range 0 to 0.08 EUR/Sm3 and consumption of fuel is taxed with approx. 0.1 EUR/Sm3 burned. This has brought forward significant changes in operational procedures and technology development on the Norwegian oil and gas installations compared to installations in other oil and gas regions throughout the world. Focus has increased on keeping the power requirement down, avoiding unnecessary fuel consumption and designing more energy efficient systems. The most efficient way of achieving this is by installing cold process flares and steam cycles on existing or new gas turbines to form Combined Cycles (CC). In Norway three steam cycle plants fueled by gas turbine exhaust are under completion on offshore oil and gas installations. The overall electrical efficiency of these plants is around 50%. When steam is extracted for process heat the overall thermal efficiency is higher. Compared to conventional simple cycles the combined cycle reduces consumption of fuel gas and emissions of CO2 and NOX with minimum 25%. When designed as alternative to conventional simple cycle solutions, a combined cycle represents an alternative investment reducing the size and/or the number of gas turbines needed. This gives a good contribution to the overall Life Cycle evaluation in favor of the combined cycle option when compared to the simple cycle option.
The U.K. Offshore Operators Drill Cuttings Initiative: New Ways of Seeking Solutions
Authors: Faulds Eric C.
Published: December 2007

Drill activity in the Central and Northern areas of the North Sea has created deposits of drill cuttings on the seabed at the drilling sites. Many of these deposits are contaminated with oil used during the drilling process. The environmental significance of these deposits needs to be established and consideration needs to be given to the best environmental practice in dealing with this legacy of drilling activity. It is not known if the best environmental practice will be to leave the deposits in place or to remove them. If removal is the best option then equipment will need to be developed to do this. These issues have the potential to initiate a confrontation debate between the oil and gas industry, academics, regulators and environmental pressure groups. In recognition that such issues must be handled differently post Brent Spar the U.K. Offshore Operators Association have initiated a programme of research and development which will not only address the scientific and technical issues but will also involve all stakeholders in an open and transparent process to address the issues such that the Best Environmental Practice can be identified and the Best Available Techniques be developed. It is believed that the process being adopted by the industry is unique and could form the model for the resolution of other environmental and publicly sensitive issues.
Brent Field Depressurization Management
Authors: Gallagher J. J. , Kemshell D. M. , Taylor S. R. , Mitro R. J.
Published: December 2007

The Brent Field commenced production in 1976, with annual oil production peaking in 1984 at 410 Mbbl/d. Since the mid 1980s, oil production has been declining, but because of the high solution GOR substantial gas reserves remain, dissolved in the residual and bypassed oil. In 1992 the decision was taken to depressurize the Brent Field to recover an additional 1.5 Tscf of gas and 34 MMstb of oil, extending the field's life by 5-10 years. This would entail redevelopment of three of the four Brent platforms at a total cost of £1.3 billion to install process facilities for low-pressure operations, to reduce operating costs, to implement safety upgrades, and to refurbish facilities. The fourth platform was also upgraded but no low-pressure facilities were installed. Preparation of the platforms for long-term field development was completed at the end of 1997.

This paper addresses the processes and systems to measure reservoir performance against plan as depressurization of the Brent Field gets underway. By several measures, 1998 has been a year of significant change. The number of well entries, gas export, gross liquid production, and reservoir pressure change were all at their highest ever levels, whilst the field's oil production remained significant in U.K. terms.

Implementing the reservoir management strategy requires striking an appropriate balance between well activity which provides an immediate return on oil or gas production and well activity which is to produce mainly water in order to liberate gas for later benefit. Essential to the decision making process is the acquisition of surveillance data, of sufficient quality and coverage, to allow proper tracking of the rapidly changing field conditions. This surveillance data then needs to be translated quickly into meaningful information, such as graphical displays of oil/gas/water distribution and quantification of parameters such as free gas cap size. This information is compared with previous predictions, with the history-match being revised where necessary, resulting in continued refinement of the static and dynamic reservoir models. Accordingly, depressurization performance can be monitored against plan and variances recognised early, leading to the optimum response in production or investment profile.
The Machar Field, Unlocking the Potential of a North Sea Chalk Field
Authors: Brown Alastair , Davies Merv , Nicholson Hugh , Gane Brian R.
Published: December 2007

The Machar field is located in UKCS block 23/26a. BP Amoco operate the field as part of the ETAP (Eastern Trough Area Project) development. The reservoir is mainly low permeability (less than 1 millidarcy), fractured chalk. Production rates from appraisal wells in the 1980s and early 1990s were disappointing at 2,000 to 8,000 bpd, which reduced the economic attractiveness of developing the field.

The Machar Field is now under development and recent production wells have delivered flowrates in excess of 30,000 bpd. These improvements have been achieved by close and careful integration of all aspects of well planning and operations which have evolved over several years. This case history discusses some of the areas which have contributed to unlocking the chalk potential of the Machar field. These are, use of a phased development; optimisation of well planning, fracture identification and acid stimulation to provide highly productive wells.
Sharing Knowledge of Exceptional Achievements to Accelerate Change and Enhance Competitiveness
Authors: Brooks-Rooney Annette , Burnett S. , Keogh W.
Published: December 2007

Stretch Performance Network (SPN) was established in 1996 as a response to some of the key challenges facing the UK oil & gas industry:

sustained low oil prices environmental and societal pressures restructuring of the industry improving competitiveness

It was created by a group of individuals who share a common ethos about the value of learning in enhancing business performance and the quality of mutual respect necessary to support this concept. Members include Global Marine Integrated Services, BP Amoco, BG plc, Conoco, AMEC, Halliburton Brown & Root, Sema Group, Trident Consultants, Scottish Enterprise and OPITO.

SPN is a not-for-profit organisation that seeks to work collaboratively to improve the long term effectiveness and efficiency of the UK oil & gas industry and ensure its survival in an increasingly challenging and competitive environment. It aims to achieve this through:

the development and application of business transformation tools, processes and models which identify and capture achievement and learning store that knowledge and provide a means for sharing and exploitation among its Member network and beyond.

This paper will highlight the role of SPN, its integrated products, services and competencies, and will provide a case study of their application, outcomes and benefits.