bluuebunny/crossref_metadata_2025 huggingface dataset:
Deployment of an SeROP Predictor Tool for Real-Time Bit Optimization
Authors: Guerrero Christine A. , Kull Bobbie Jo
Published: December 2007

Since 1965, specific energy (SE) principles have been used to predict bit performance and analyze rate of penetration (ROP) and bit efficiency(1). Factors that create drilling inefficiency include bit dull, bit balling, bottomhole balling/cleaning issues, torque/drag, and drillstring vibrations. These are often evident with high SE values. Based on these principles, Chevron has established proprietary relationships for bit-specific coefficient of sliding friction and mechanical efficiency as a function of the rock's confined compressive strength (CCS). Chevron then uses these relationships to predict reasonable and achievable ROPs with the associated bit torque for several bit types most commonly used in their global operations. The effect of mud weight, blade count, and cutter size to the coefficient of sliding friction and efficiency are considered in the ROP predictions(2). These relationships have proven to be of high value in the creation of a globally accurate drilling tool for improving overall bit performance and reducing well costs.

Applied real time, the tool identifies inefficient drilling conditions and provides operations personnel with the reliable information needed to make more informed decisions and achieve the best possible performance out of the bit that is in the hole, as well as quantify the impact of parameter changes.

This paper will present a number of global case histories showcasing Chevron's rapid deployment of the Specific Energy Rate of Penetration (SeROP) Predictor Tool to maximize its value and reduce drilling costs. These case histories used evolving strategies, which varied according to the well's complexity and the wellsite resources available. Also shown are the incremental benefits gained when bit performance prediction/selection modeling was coupled with real-time down-hole measurements. The paper also presents the limitations and increased data requirements that are required for complicated wellbore geometries.
Remedial Frac Operations in Deep Tectonic Wells: Mechanical and Operational Issues
Authors: Rylance M. , Doig T. W. , Hoff R. , Knopp S. N.
Published: December 2007

The Cupiagua retrograde Gas-Condensate reservoir, in the Llanos foothills of Colombia, was developed using a fast-track approach to provide production against an aggressive delivery plan. Unfortunately, an unusually severe condensate-banking effect combined with difficult perforating and drilling induced damage, meant that deliverability of the wells failed to achieve the desired levels.

This paper describes the approach that was taken to economically remediate these multiple-stacked reservoirs by the novel deployment of a through-tubing Frac-String. In addition, due to the highly tectonic regional-stresses, the final variant of this through-tubing frac-string was designed to permit surface treating pressures of up to 18,500 psi.

This solution was primarily possible due to the mono-bore completions with which the Cupiagua field had been originally developed. The frac-string was deployed through tubing with open perforations on the annulus; in addition variants, such as a slim-hole frac-string, allowed deeper zones within smaller production-liners to also be stimulated. The technology of the Frac-strings was incrementally developed over time and in this way new and more increasingly complex challenges could be undertaken without dramatically increasing the overall risk on each treatment.

More than 136 deployments of various string variants have been performed successfully; and even though annular tool clearances have been as low as 1/20" there has not been a single stuck-pipe incident to date. Throughout these operations the frac-string pressure test history has been faultless and the cumulative proppant placed during the frac treatments has amounted to more than 6,250,000 lbs.

Finally, significant production increments have also been achieved, the first well increased in productivity from ca. 8,000 bcpd to 18,000 bcpd and numerous low delivery wells were stimulated into becoming major producers. Individual case studies will be presented to support this, along with the production histories of the first 3 treatments.

Remedial treatments, of these deep tectonic wells, have been economically feasible due to the ability to deploy a frac-string through the existing completions. Variations on the actual rig-up, deployment and design have allowed economically less favourable wells to become feasible candidates. In addition, the continued field development, extension and infill drilling has also been made possible by the application of this novel approach.
Deployment of a Riserless Mud-Recovery System Offshore Sakhalin Island
Authors: Brown J. D. , Urvant V. V , Thorogood J. L. , Rolland N. L
Published: December 2007

A riserless mud recovery system enables dual gradient subsea drilling operations to take place with the well open at the seabed. There are no pressure containment devices at the wellhead, but as with earlier systems developed for deep water drilling [1], mud and cuttings are returned to the rig by means of a subsea pumping system, fluid recovery hose and umbilical. The system was field tested as part of the Norwegian DEMO2000 project [2]. Subsequently, it has seen operational service in a multi-well drilling campaign in the Caspian Sea.

This paper describes how the system was implemented in a remote area exploration drilling operation off Sakhalin Island. Following experience in 2004 and 2005 [3] a clear business case emerged with the underlying drivers of limited weather window, shallow gas and stringent discharge regulations. Accordingly a formal project was established and a number of critical risk reduction studies were carried out in relation to shallow gas and integrity of the return hose under high current conditions. Correct interfacing onboard the rig required careful choice of location, power supply, wellhead and remotely operated subsea vehicle. There changes were verified by means of a formal hazard and operability review. A significant part of the effort involved gaining certification of the equipment for use in the Russian Federation in parallel with the fabrication, acceptance testing, mobilisation, offshore installation and commissioning of the system. The paper concludes with a review of the operational experience from the 2006 drilling season along with the associated lessons learned and forward plan.
A Streamline-Based Model for Potentiality Prediction of Enhanced-Oil Recovery
Authors: Hou Jian , Zhang Shun-kang
Published: December 2007

A pseudo-three dimensional model of potentiality prediction is proposed for enhanced oil recovery based on boundary element method (BEM) and streamline method in this paper. The potential distribution of the flow through porous medium under the complicated boundary condition is solved with BEM, which overcomes the defects of traditional mirror image method. Further more, the method for tracing streamlines between injectors and producers is presented. Base on this, numerical solution can be obtained by solving the seepage problem of stream-tube with the consideration of different methods of enhanced oil recovery. In this way, the aim of dynamic prediction can be achieved. The advantage of the method in this paper lies in the fact that it can realize the dynamic calculation with different well patterns in any shape by easily considering different physicochemical phenomena with less calculating time and good stability. Based on the uniform theory basis - streamline method, different models including CO2 miscible flooding, polymer flooding, alkaline/surfactant/polymer flooding and microbial flooding are established in this paper. Polymer flooding model has been successfully applied to the EOR potential evaluation in different reservoirs of Shengli oilfield.
Development of a Dual Media Full-Field Simulation Model to Optimize Injection/Production Strategy for Two Communicating Mature Carbonate Reservoirs
Authors: Chiffoleau Yann , Shenawi Shamsuddin , Yuen Bevan , Al-Garni Saad A. , Lyngra Stig , Al-Shammari Methgal A. , Al-Shammary Turky M.
Published: December 2007

An advanced integrated reservoir study has been performed for a giant mature oil field in Saudi Arabia. The field is composed of two naturally fractured reservoirs that are separated by a thick non reservoir formation. Same pressures have been recorded in both reservoirs since the start-up of production. Consequently, the two reservoirs are clearly in direct hydraulic communication. The geological data support that the communication is taking place through fractures swarms (sub-seismic faults) which affect the two reservoirs. A multidisciplinary approach was used to characterize and model the location of the fracture swarms by integration of available dynamic and static data. The resulting fracture grid of the simulation model combines diffuse fractures and fracture swarms.

This paper discusses the ways to simulate these dual porosity – dual permeability (DPDP) systems that behave very differently, but still interact with each other. The lower reservoir is a tight matrix with diffuse fractures. Fracture density and capillary pressure control the oil recovery in this mixed wettability carbonate rock. Moreover, fracture swarms create reservoir anisotropy, which causes preferential fluid paths. In the upper reservoir, the matrix is very permeable with highly conductive strata. Due to the high matrix permeability, the dynamic contrast between the matrix and fracture media is low; thus, the fracture swarms only act as global permeability enhancers.

This fracture multi-scale approach enabled us to history match the 5 millions active cells model (DPDP mode). The modeling accuracy was significantly improved by better representing the physics of the fracture-controlled system. It also provided new insight into the complex interactions between the two reservoirs through fracture swarms. The production history supports that these exchanges have been controlled by pressure regimes and fluids segregation in the fracture swarms. A better understanding of these communications led to a more optimized future injection/production development strategy.
Integrating Drilling-Fluid Optimization and New Technology Improves Carbonate Reservoir Evaluation
Authors: Okuyiga Moyosore , Berrim Ahmed , Haddad Sammy , Xian ChengGang , Abu Lawi Majed , Al-Naser Jamil
Published: December 2007

Wireline formation testing in low permeability carbonate reservoirs of the U.A.E. has been challenging with frequent tool plugging, extended pumping time, and multiple trips out of the hole. A recent well, drilled offshore Abu Dhabi for ADMA-OPCO, penetrated the main three reservoirs and presented a rare opportunity to address these challenges. The tested intervals contain multiple thin zones, which make it difficult to predict reservoir fluid types from open-hole logs or pressure gradients alone. An extensive Downhole Fluid Analysis (DFA) program was needed for fluid types and contacts determination.

A multidisciplinary team between the operator and the service company was organized to carefully consider the challenges mentioned above, identify the source problems and recommend a solution. The solution involved the economically viable replacement of the drilling fluid with a low solid content fluid prior to the wireline formation testing operations. A new wireline formation tester technology, the Extra Large Diameter module (XLD), was also recommended to replace the dual-packer at a broad permeability range. The combination of drilling fluid displacement, XLD utilization and the addition of two pumps proved to be major factors in reducing the overall job duration, rig time, and smoothly achieving the required objectives.

As the results, a record job including 27 DFA stations (16 with samples), 2 mini-frac stations and in access of 90 pressure points were achieved. The DFA and samples provided significant answers and clues to a broad range of reservoir issues including compartmentalization, fluid compositional variation, the unexpected identification of oil, oil reserve assessment, and gas compositional analysis to understand its origin and potential contact migration. The wireline formation testing results have added direct values to reservoir evaluation and development. In this work, a best operating practice for similar reservoirs is demonstrated.
Topdrive Casing Running and Drilling Tools Reduce Well-Construction Costs and Increase Safety
Authors: Shahin Nazir , Cummins Tracy
Published: December 2007

A new portfolio of remotely operated casing running and casing drilling tools that connect to the rig's top drive and use the top drive's rotational power, hoisting and circulation capabilities for improved casing running operations. The value is increased safety and efficiency compared to conventional running operations, plus the ability to instantly push down or reciprocate while rotating and circulating, helping to get strings to bottom.

Applications include normal casing installation in pre-drilled wells on most rigs with a top drive system, and extended reach, deviated, and troublesome wells. Additional application includes casing drilling technology where the entire well bore can be drilled with the casing string; eliminating the need for drill pipe and bottom hole assemblies.

The new system combines several conventional casing handling tools into one:

Power Tong Main Hoisting Elevator Single Joint Elevator Fill-up and Circulation Tool Weight Compensator Link Tilt (Stabber) Safety Interlock System

Lab and field test results have proven that the new technology provides:

Greater casing running efficiency Increased safety by reduction of personnel and remote operation.

Step change in technology will allow oil & gas operators to increase drilling performance and reduce well construction costs.
Multiobjective Optimization With Application to Model Validation and Uncertainty Quantification
Authors: Schulze-Riegert Ralf , Krosche Markus , Fahimuddin Abul , Ghedan Shawket
Published: December 2007

History Matching in Reservoir Simulation, well location and production optimization etc. is generally a multi-objective optimization problem. The problem statement of history matching for a realistic field case includes many field and well measurements in time and type, e.g. pressure measurements, fluid rates, events such as water and gas break-throughs, etc. Uncertainty parameters modified as part of the history matching process have varying impact on the improvement of the match criteria. Competing match criteria often reduce the likelihood of finding an acceptable history match. It is an engineering challenge in manual history matching processes to identify competing objectives and to implement the changes required in the simulation model.

In production optimization or scenario optimization the focus on one key optimization criterion such as NPV limits the identification of alternatives and potential opportunities, since multiple objectives are summarized in a predefined global objective formulation. Previous works primarily focus on a specific optimization method. Few works actually concentrate on the objective formulation and multi-objective optimization schemes have not yet been applied to reservoir simulations.

This paper presents a multi-objective optimization approach applicable to reservoir simulation. It addresses the problem of multi-objective criteria in a history matching study and presents analysis techniques identifying competing match criteria. A Pareto-Optimizer is discussed and the implementation of that multi-objective optimization scheme is applied to a case study. Results and consequences for the uncertainty quantification are presented.
Foam Drilling Simulator
Authors: Paknejad Amir , Schubert Jerome J. , Amani Mahmood
Published: December 2007

Although the use of compressible drilling fluids is experiencing growth, the flow behavior and stability properties of drilling foams are more complicated than those of conventional fluids. In contrast with conventional mud, the physical properties of foam change along the wellbore. Foam physical and thermal properties are strongly affected by pressure and temperature. Many problems associated with field applications still exist, and a precise characterization of the rheological properties of these complex systems needs to be performed. The accurate determination of the foam properties in circulating wells helps to achieve better estimation of foam rheology and pressure.

A computer code is developed to process the data and closely simulate the pressure during drilling a well. The model also offers a detailed discussion of many aspects of foam drilling operations and enables the user to generate many comparative graphs and tables. The effects of some important parameters such as: back-pressure, rate of penetration, cuttings concentration, cuttings size, and formation water influx on pressure, injection rate, and velocity are presented in tabular form.

A discretized heat transfer model is formulated with an energy balance on a control volume in the flowing fluid. The finite difference model (FDM) is used to write the governing heat transfer equations in discretized form. A detailed discussion on the determination of heat transfer coefficients and the solution approach is presented.
Estimation of Permeability From Wireline Logs in a Middle Eastern Carbonate Reservoir Using Fuzzy Logic
Authors: Abdulraheem A. , Sabakhy E. , Ahmed M. , Vantala A. , Raharja I. , Korvin G.
Published: December 2007

Permeability is one of the most difficult properties to predict, especially in carbonate reservoirs. The most reliable data of permeability, obtained from laboratory measurements on cores, do not provide a continuous profile along the depth of the formation.

This paper presents the use of fuzzy logic modeling to estimate permeability from wireline log data in a Middle Eastern carbonate reservoir. In this study, correlation coefficients are used as criteria for checking whether a given wireline log is suitable as an input for fuzzy logic modeling. The coefficients are enhanced if they are evaluated with respect to the logarithm of core-based permeability values of the given well.

After training the fuzzy model on a layer in a given well, permeability predictions were made for other layers in the same well. These predictions were in excellent agreement with permeability values obtained from cores. It was also observed that Subtractive Clustering technique gives better predictions of permeability when compared with Grid Partitioning technique.

A parametric study was also conducted to see the effect of type and number of membership functions, combination of log input parameters, and data size on predictions of permeability. The possibility of training the fuzzy program on one well and testing it for other wells in the same formation is also explored.
Critically-Stressed-Fracture Analysis in Naturally Fractured Carbonate Reservoir–A Case Study in West Kuwait
Authors: Verma Naveen K. , Al-Medhadi Fahed , Franquet Javier A. , Maddock Robert , Natarajan D. , AL-Mayyas Eman
Published: December 2007

This paper presents the methodology to identify critically stressed fractures, CSF, in naturally fractured reservoirs. A natural fracture is considered to be critically stressed if the ratio of shear and normal stresses acting on the fracture surface exceeds the frictional strength of the reservoir rock. The main objective is to identify the critically stressed fracture trends in the reservoirs in order to design wellbore trajectories that efficiently intersect theses fracture trends. In addition, geomechanical analysis for drilling scenarios under depleting reservoir conditions addressing well-bore stability is attempted to formulate drilling and completion strategy.

Critically stressed fracture identification has several important implications on fluid flow behavior through naturally fractured porous media. It has been shown that fluid flow in fractured rocks is largely controlled by critically stressed fractures; therefore, critically stressed fracture analysis may enable to systematically identify producing fractures in the reservoirs that mainly produce through natural fractures.

The CSF analysis includes the mechanical property characterization of the formations and the in-situ stress tensor description acting on the reservoirs. The fracture orientations from core description & borehole image log interpretation were used for the CSF analysis because fracture dip and strike are needed for the stress calculation on fracture planes. This analysis is particularly useful where several fracture trends are identified in a reservoir, with some trends more likely to be open and productive due to horizontal stress anisotropy. The case history illustrates application of CSF Analysis in conjunction with geomechanical wellbore stability analysis in selection of optimal well trajectory and formulation of drilling and completion strategy for producing a naturally fractured carbonate reservoir.
The Identification of Condensate Banking With Multiphase Flowmeters – A Case Study
Authors: Theuveny B. C. , Maizeret P. D. , Hopman N. S. , Perez S.
Published: December 2007

The identification of condensate banking has always been a challenge. Furthermore, large productivity losses can result from the absence of early detection of a condensate bank in the near well bore area of the well. The traditional means of detecting a condensate bank range from comparison of the dew point to downhole pressure measurements, identification of composite radial models and quantification of skin using pressure transient analysis. One of the methodologies that have been more theoretical than practical has been the detection of a leaner stream of effluent at the well head during production. This type of approach has been quite challenging in the past, as a high resolution measurement of the condensate to gas ratio is essential to a successful diagnostics of condensate banking.

The paper presents a case of analysis of the development of a condensate bank during a well test. The multiphase flowmeter identified a gradual reduction of the condensate to gas ratio with increasing choke sizes. The methodology of diagnostics is demonstrated, in particular with the discrimination against liquid loading issues.

The PVT compositional analysis provides a verification of the analysis, and the observation of the evolution of the phase diagram leads a further understanding the downhole and near well bore thermodynamic phenomena.

The degradation of the productivity of the well is also analyzed, with a significant drop of gas productivity observed even on smaller choke sizes at the end of the test.

Finally the paper presents a numerical simulation match of the data and provides a number of recommendations for the utilization of single well - near well bore compositional models to help interpreter to obtain better and simpler matches.

This paper provides a new methodology to make full use of the benefits of the dual energy gamma Venturi multiphase flowmeters in the evaluation of gas wells.
Identification of High-Porosity Reservoir Sands From 3D-Seismic Attributes Using Neural Network Technique in South Umm Gudair Field, Kuwait
Authors: Thakur Ram Kumar , Duval Frederic , Boibien Claude , Pages Gilles
Published: December 2007

The South Umm Gudair Field is a multi-accumulation structure with the most prolific production of oil from a Ratawi Oolite reservoir (Neocomian). The historic ultimate seal held by the thick Ratawi Shale Member, displays embedded multilayered oil bearing reservoir sands. Sands were sedimented as thin tidal bars anastomosed with distributary and tidal channels deposited under pro-deltaic to delta front environment.

To delineate this complex reservoir, a neural network technique was applied to estimate effective porosity integrating well information and 3D multi-attributes between seismically mapped sequences. This method is more efficient than conventional estimation with the ability to build a non-linear relationship between seismic traces and target porosity logs for interpolation. The combination of 20 seismic attributes including impedance derived by model based inversion was selected on the basis of ranking of error factors.

The network was trained with effective porosity available at well locations. It subsequently recognized not only that pattern, but also similar patterns by generalization in the study area. The effective porosity cube was generated by the processing of 3D seismic data with this trained network. The representative sections extracted from this volume highlight the limited extent of reservoir sands within the sequences which has also been supported by the simulations of lithofacies with Sequential Gaussian method using well data. The trajectory of the proposed lateral wells are designed in sequences-2 & 4 to intersect the porous sand at the optimum location to ensure good drainage of these reservoir units. The reservoir sand corresponding to upper sequence-4 shows widespread development in the western part of the area of interest with better connectivity, but is shaling out eastward of the field.

The paper focuses on the methodology of identification of thin lenticular high porosity reservoir sands to plan for side-tracking existing deeper wells and drilling appraisal & delineation wells.
The Next Major Step in Total Hands-Free Pipe Handling—No Derrickman in the Derrick Racking and Unracking Pipe
Authors: Richard Dave
Published: December 2007

The paper identifies the challenges that were overcome to realize hands free tripping, racking and un-racking of drill pipe and collars in medium and large land based drilling rigs through the development of a new technology racking board pipe handling system. The steps of development and design involving Mechanical, Electrical and Robotic Motion Control Engineering Technologies combined with drilling operations knowledge and experience are laid out to show how adapting these new ideas to existing double and triple drilling rig masts without any structural mast modifications was achieved. A comparison to offshore racking board pipe handling systems highlights the technical and economic difficulties experienced in applying the land based systems successfully with frequent moves, weight/size restrictions and reliability concerns. Field gathered tripping and connection test times in comparison to a human Derrickman working the racking board are put forward. Field tests further describe how drilling hands on the drill floor typically needed to set pipe back and lead pipe into well center during tripping in-hole and out-hole are eliminated. The paper looks at how conventional robotic motion control technology has resulted in reliable "Nintendo-style" control operation with smooth solid control of moving pipe. Further discussions in the paper examine the current obstacles that remain to completely remove drilling personnel from the harms way on the drill floor. Finally, the paper will show how this direction of design development and implementation in safe drilling rig equipment is necessary to keep employees healthy, productive, profitable and working in the drilling industry.
Drilling Without WOB: Dream or Reality? An Effective Field Test by Total Angola
Authors: Simon Christophe , Goyallon David , Poloce Jean-Paul , Sellami Hedi , Gerbaud Laurent , Dourfaye Alfazazi
Published: December 2007

Recent developments in PDC bit modelling and single cutter analysis have enabled to design a new generation of cutting structures – based on the optimization of a specific interactive cutting mode – that generates, by the mere drilling action of the cutters, an axial force oriented in the drilling direction: a negative weight on bit.

This paper presents the application of this new PDC bit design and shows that WOB can be significantly reduced in a wide range of formations. A monobloc 8″1/2 PDC bit was designed, tested in laboratory, and self penetration was clearly achieved in field conditions.

A full PDC bit design methodology using a new PDC cutters geometry optimized for a maximum thrust effect, along with specific manufacturing procedures for high-level precision in cutter positioning, were developed for this specific new bit generation.

Laboratory tests showed that it was possible to drill without WOB at a high rate of penetration and with a small increase in specific energy. Preliminary field tests in cement demonstrated that self penetration – drilling with the neutral point just above the bit – was possible with specific surface control, and a first operational application was conducted by Total E&P Angola.

This new bit technology has the potential to increase bit performance, specifically in operating conditions where power is available but WOB is limited due to friction, buckling or reduced vertical depth. The ability to drill with reduced WOB – or even without any WOB – should extend the potential of existing drilling technologies such as Extended Reach Drilling, Coiled Tubing or Steerable Motor in sliding mode and reduce axial vibration, thus increasing the MTBF of downhole tools.
PDC Casing Drilling Improves HS&E, Cuts Drilling Costs—West Africa
Authors: Hartsema Klaas , Gabon Shell , Aliko Enis , Campos Jaime , Clark Lester , Delgado Franck , Folling Peter , Wingate John
Published: December 2007

Conventional drilling techniques were utilized by the operator in Gabon to drill surface-hole through fractured carbonates prone to severe losses up until 2004. At that time, the operator launched a series of cost-cutting initiatives, one of which was the employment of Casing Drilling technologies.

Casing/Liner drilling is the process of drilling or reaming down a casing/liner interval utilizing a Casing Drill Bit. The casing/liner replaces the drill-pipe and is rotated at surface by the rig's top-drive. This system enables problematic zones to be drilled and sealed-off in one run reducing potential non-productive time (NPT) associated with hole problems, eliminating tripping-time for conventional drill-pipe and bottom hole assemblies (BHAs) and improved rig-floor safety by eliminating the risk associated with pipe handling.

The bit company recommended a polycrystalline diamond compact (PDC) – drillable Casing Drill Bit that is screwed onto the bottom of the casing. This simple, yet robust tool would ensure the greatest chance of success. Three Casing Dill Bit sizes have been run successfully to date on six wells; 12-1/4" (modified to 12-3/4") and 16".

Early runs raised some concern as to whether the casing connections could withstand the torque levels required to drill with casing. The first three runs used a 12-1/4" Casing Drill Bit run on 10-3/4" casing. Total mud losses and high torque levels were experienced during these runs. The Casing Drill Bit size was subsequently increased to 12-3/4" thereby increasing the annular clearance, reducing borehole friction and potential losses. The modification proved successful with the fourth well drilled without losses and torque levels reduced by half compared to the first three runs.

The fifth and sixth runs employed a 16" PDC Casing Drill Bit conveyed on 13-3/8" casing. On the fifth well the bit was pulled-out prematurely due to formation problems. The bit came out in excellent condition with no wear and only one missing PDC cutter. The same bit was re-run on the sixth well where it drilled to section total depth (TD) with full returns throughout the run.

The paper will describe the PDC Casing Drill Bit system, its performance in Gabon plus the systems positive economic impact and safety benefits.
Hydraulic Blowout Control Requirements for Big-Bore and HP/HT Developments: Validation With Field Experience
Authors: Oudeman P.
Published: December 2007

Although advances in drilling and well intervention technology have made blowouts a rare phenomenon, their consequences are often of such a magnitude that for each development a contingency plan should be available aimed at limiting the damage and regaining control over the outflow of the well rapidly. This plan should consider all possible blowout scenarios and the corresponding response. When capping, the most efficient method, is not an option, e.g. for subsea or underground blowouts, downhole injection of kill fluids through an existing conduit or relief well(s), the hydraulic or "dynamic" kill, is the next best alternative. To plan for such an operation prior to actually spudding the development wells, a number of parameters needs to be known such as the required number and dimensions of relief wells, kill fluids and kill rates, pump capacity etc. For HPHT and big bore developments, these requirements cannot be derived from experience.

It is shown here that the requirements depend on a limited number of factors such as the pressure regime of the blowing formation and flow resistance of the blowing well. This allows formulation of guidelines for hydraulic blowout control for (un-) conventional developments, even when the exact circumstances of a blowout are not known, as is the case in contingency planning.

A comparison with selected field cases of blowouts demonstrates that the formulated guidelines match the experience with actually killing these blowouts in terms of the number of wells, pump rates, and kill fluids etc. that were eventually required. This gives the confidence that the guidelines are a good starting point for contingency planning. The case of a giant North Sea gas field is discussed to demonstrate this.
Survey Accuracy Extends Well Displacement at Minimum Cost
Authors: Landry Bart , Poedjono Benny , Akinniranye Goke , Hollis Mike
Published: December 2007

The increased use of horizontal exploitation of formations for improved resource recovery has resulted in a trend towards denser well spacing and extended lateral lengths. The resulting reduction in distance between wellbores has intensified the need for accurate data on wellbore positions and trajectories. This paper explores the challenges of developing reliable positioning data and examines various mechanisms for ensuring optimum well separation distances essential to optimize waterflood sweep efficiency. Case histories from land drilling operations will be discussed to demonstrate the design and application of a well survey program that is both highly accurate and cost effective.

Among the program components to be discussed are methods for determining the accuracy of existing wellbore data and statistical analysis to assess how closely predictive models match actual well placements. Support data for analysis was generated from existing reservoir models and statistical gyro surveys. Additional insights were gained by examining the causes of measurement-while-drilling (MWD) errors, and accuracy was increased by finding new ways to minimize magnetic errors induced by the bottom hole assembly (BHA). A database was compiled to compare raw MWD data with corrected survey data, with two goals in mind:

■ Reduce the average level of destructive anomalies per well by investing in more accurate processing for each BHA. ■ Increase the lengths of the lateral wells by 50% for more efficient resource recovery.

By better understanding the extent and cause of existing survey inaccuracies, and developing improved methodologies for reliable data collection and analysis, this study has contributed to both the safety and the economic viability of today's increasingly complex drilling programs.
Intelligent-Well Technology Used for Oil Reservoir Inflow Control and Auto-Gaslift, Offshore India
Authors: Konopczynski Michael , Tolan Mike
Published: December 2007

The use of intelligent well technology is growing as Oil and Gas operators try to improve the management of hydrocarbon reservoirs and exploit the recovery of reserves more efficiently. The abilities to monitor conditions down-hole in real time, and control the flow of fluids between the reservoir and the partitioned wellbore without physical intervention, inherent in intelligent well technology enable the operator to achieve these objectives. One method of employing intelligent well technology is to commingle, in a controlled process, the production from a gas reservoir or gas cap with the principle production from an oil reservoir in order to reduce the hydrostatic head of the produced fluids in the production conduit and enhance production of the oil. We call this process, "Auto-gaslift". Use of auto-gaslift reduces the capital investment required to construct the infrastructure (compressors, separators, dehydrators, distribution lines) necessary for conventional gaslift.

Intelligent well technology is necessary to effectively control the auto-gaslift process by monitoring the performance of the oil and gas sources, and by controlling the addition of gas to the production in order to optimize the production of fluids. The optimization process is similar to methods of conventional gaslift. With auto-gaslift however, unlike conventional gaslift, the productivity of the gas source is uncertain, and pressure and productivity can change with the life of the well. Additional attention must be applied to the design of the downhole flow regulating valve on the gas zone to ensure that it is properly sized for the application over the range of gas and oil reservoir performance, fluid compositions and reservoir pressure for the life of the well.

This paper describes a multi-well application offshore India in the Panna oil field using SmartWell technology for auto-gaslift, as well as to control inflow from a segmented horizontal wellbore in the oil reservoir. The paper describes the SmartWell completion design to control inflow of unwanted effluents from a horizontal well, and to use auto-gaslift to maximize production.
Predrill Estimation of Subsalt Fracture Gradient: Analysis of the Spa Prospect to Validate Nonlinear Finite Element Stress Analyses
Authors: Fredrich J. T. , Engler B. P. , Smith J. A. , Onyia E. C. , Tolman D. N.
Published: December 2007

Deepwater areas offshore the Gulf of Mexico, Angola, and Brazil contain vast oil and gas deposits that underlie thick salt formations. Drilling wells to recover these resources can be challenging because of extreme water and reservoir depths, adverse environmental conditions, and complex tectonics. In particular, stress changes can occur in the vicinity of salt diapirs that are of sufficient magnitude to affect fracture gradient and wellbore stability, and the vast majority of difficult drilling events associated with salt diapirs in the deepwater Gulf of Mexico are in fact associated with the salt – sediment interface. In prior work, non-linear finite element analyes were used to identify the style and magnitude of near-salt stress changes for several idealized diapir geometries. While providing insights, the analyses for idealized diapir geometries remain essentially unvalidated. The work reported here is intended to provide key validation for the conceptual model and numerical methodology developed to predict near-salt stress changes. In 2002, Conoco drilled the Spa prospect, Walker Ridge 285 #1, in the Gulf of Mexico to a depth of 29,452 feet MD / 29434 feet TVD, penetrating a nearly ten thousand foot salt section. While the potential for reduced fracture gradient below salt was recognized in well planning, pre-drill pore pressure and fracture gradient estimates were nevertheless based on seismic velocities in the adjacent abyssal basin. The sub-salt section was difficult to drill, and several formation integrity tests were performed. We developed basin-scale finite element models to represent the geometry of the salt diapir and performed non-linear geomechanical simulations to predict the stress changes in and around the diapir. The simulations predict stress perturbations that vary spatially in accord with the complex and irregular salt geometry. Significant perturbations are predicted adjacent to the salt diapir, and the models predict the reduction in fracture gradient observed sub-salt (nearly 3 ppg). This work thus serves to validate non-linear finite element stress analysis techniques that can be applied to reduce risks when drilling through massive salt diapirs. Besides providing a geomechanical basis for understanding sub-salt fracture gradient reductions, this work also demonstrates the potential for significant stress distortions associated with topography along the top of salt.
A New Approach for Reliable Estimation of Hydraulic Fracture Properties in Tight Gas Wells
Authors: Cheng Y. , Lee W. J. , McVay D. A.
Published: December 2007

Gas wells in low-permeability formations usually require hydraulic fracturing to be commercially viable. Pressure transient analysis in hydraulically fractured tight gas wells is commonly based on analysis of three flow regimes: bilinear, linear and pseudo-radial. With current well test analysis techniques, a reliable estimation of hydraulic fracture and reservoir properties relies on occurrence of all these three flow regimes. Without the presence of pseudo-radial flow, neither reservoir permeability nor fracture half length can be independently estimated. In other words, to reliably estimate fracture half length, reservoir permeability has to be known. Since pseudo-radial flow is often absent, the estimation is uncertain and unreliable. On the other hand, elliptical flow, which exists between linear flow and pseudo-radial flow, is of long duration (typically months to years). We can acquire much rate and pressure data during this flow regime but no practical well test analysis technique is currently available to interpret these data.

This paper presents a new approach to reliably estimate reservoir and hydraulic fracture properties from analysis of constant-rate drawdown pressure data obtained during the elliptical flow period. The method is based on equations modeling the elliptical flow regime and is applicable to estimate effective fracture half length, formation permeability and skin factor independently for both infinite- and finite-conductivity fractures. The method is iterative and features rapid convergence. It can estimate formation permeability when pseudo-radial flow does not exist. It can also be coupled with stable deconvolution technology, which convert variable production-rate and pressure measurements into an equivalent constant-rate pressure drawdown test, and thus provide property estimates from readily available, noisy production data. We present synthetic and field examples to illustrate the procedures and demonstrate the validity and applicability of the proposed approach.
Beryl Alpha—Reaching Out to Recover: An Extended-Reach Drilling Upgrade Project on a 30-Year-Old Rig
Authors: Cutt Richard N.
Published: December 2007

The Beryl field in UK Block 9/13 was discovered in 1972. The 40-slot, twin drilling rig, Beryl Alpha platform (see photograph Fig. 1) installed in July 1975 was the first concrete Condeep structure installed in the North Sea. The field is heavily faulted and stratigraphically complex, generating numerous drilling opportunities with associated geological uncertainties. Extended reach wells are planned to develop resources beyond the reach of the current platform rig capabilities.

In the current industry environment where costs of semi-submersible rigs have risen dramatically and rig availability is an issue, the traditional concept of subsea satellite development is now problematic in terms of economic viability and control of schedule. The Beryl field has a number of satellite and in-field development opportunities beyond the platform's drilling reach. The concept of upgrading the Alpha drilling rigs to enable these resources to be developed by means of extended reach drilling (ERD) was conceived. The approach taken was to maximize ERD while remaining within the constraints of the existing derrick structures. This involved an innovative approach to retrofitting enhanced drilling capabilities on a 30-year old rig extending horizontal displacement from 15,000 to 25,000 ft (see field map on Fig. 2).

This paper will address project planning from inception through the development of a rig upgrade execution plan and address the well design issues for the ERD program envisaged, including potential new drilling technology applications to reduce torque and enable multiple casing strings below 9-5/8-in. casing. Beryl celebrated its 30th year of production on 11 June 2006. The field life was initially estimated to be 20 years. At the time the Alpha platform was installed, Beryl Field reserves were estimated to be approximately 400 million barrels of oil equivalent, to date over 1.3 billion barrels of oil equivalent have been produced from the Beryl field and associated satellite developments (28% from subsea wells) far in excess of the original Alpha platform funding basis. Innovative approaches to field development characterised the beginning of Beryl's productive life and are being applied today to continue the process of extending field life by reaching out to recover and discover new resources previously thought beyond reach.
An Efficient Algebraic Multigrid Solver Strategy for Adaptive Implicit Methods in Oil Reservoir Simulation
Authors: Clees T. , Ganzer L.
Published: December 2007

We propose a new, efficient, adaptive algebraic multigrid (AMG) solver strategy for the discrete systems of partial differential equations arising from structured or unstructured grid models in reservoir simulation. The proposed strategy has been particularly tailored to linear systems of equations arising in adaptive implicit methods. The coarsening process of the AMG method designed automatically employs information on the physical structure of the models; as a smoother, an adaptive ILUT method is employed, taking care of an efficient solution of the hyperbolic parts whilst providing adequately smooth errors for the elliptic parts. To achieve a good compromise of high efficiency and robustness for a variety of problem classes – ranging from simple, small black-oil to challenging, large compositional models – an automatic, adaptive ILUT parameter and AMG solver switching strategy, α-SAMG, has been developed. Its efficiency is demonstrated for eight industrial benchmark cases by comparison against standard one-level and AMG solvers as well as the pure one- level variant of the proposed new strategy. In addition, very promising results of first parallel runs are shown.
Dope-Free Tubular Connections, through Research and Development to Field Trial and Implementation: A North Sea Case History
Authors: Andersen Henrik B. , Hummer Marcus P. , Engell Rasmus C. , Verdillon Lionel , Pardé Arnaud
Published: December 2007

In 2000 Vallourec & Mannesman Tubes approached Maersk Oil with the vision of a tubular connection that requires minimum handling in its lifespan from the mill to the well, removing environmental impact from dope and increasing safety at the well site. To realize this, all application of thread compound in the field or yard was to be eliminated, and a protector design developed that enables the protector to be removed only when the tubular is ready to be run in the well.

After an initial development period Vallourec & Mannesman Tubes had a final Dopefree product ready for test. The product a transparent waxy compound applied directly on selected premium threads, serving as both storage and running dope, completely eliminate the requirements for cleaning an redoping at the wellsite. It was decided to initially perform a field test and if successful to implement Dopefree on all tubular sizes where avalaible

Maersk Oil operates wells offshore in the Danish sector of the North Sea, which are characterized by being long horizontal wells (5,000 – 20,000 ft VS) drilled in chalk reservoirs. The wells are commonly completed with 4½" or 5½" completion inside a 7" liner hung off in a 9-5/8" production casing set just above the reservoir. The liners are in some cases cemented in place to allow for zonal isolation. The driving factors for Maersk Oil to test and subsequently implement Dopefree were: Increased safety by minimizing tubular handling,Minimize environmental impact by removing dope,Increase efficiency for wireline and coiled tubing operations by eliminating excessive dope in the well.