bluuebunny/crossref_metadata_2025 huggingface dataset:
Determination of the Skin Factor for a Well Produced at a Constant Bottomhole Pressure
Authors: Kutasov I. M. , Kagan M.
Published: December 2007

A new technique has been developed for analyzing the constant bottomhole pressure (BHP) test data. The method presented in this note allows to calculate the skin factor for damaged and stimulated oil wells. Advantages of the BHP test are: (1) they do not require that well be shut in; (2) the fluid production can be easily controlled (at constant flow rate tests the BHP is changing with time); and (3) wellbore storage effects on the test data are short-lived. It is assumed that the instantaneous flow rate and time data are available from a well produced against a constant bottomhole pressure. Only records of the flowing time and cumulative production data are required to compute the value of the skin factor.

A semi theoretical equation is used to approximate the dimensionless flow rate. This formula is used to obtain a quadratic equation for determining the skin factor. The accuracy of the basic equation will be shown below. The paper includes an example o calculation.
A Simple Empirical Pipeline Fluid Flow Equation Based on Actual Oilfield Data
Authors: Osisanya S.
Published: December 2007

The selection of pipe diameter or length depends on the pressure drop available or anticipated flow rate. A simplified empirical pipeline fluid flow model equation is developed for sizing pipeline based on actual field data. The data used were the actual flow rates and pressure drops for four loading pumps and two booster pumps during the loading of two tankers. The model was used to calculate pressure drops for various flow rates while varying the pipeline length and diameter. The model was validated using classical Fanning/Reynolds number approach, API RP 41E design procedure for piping systems, and the famous Hazen-Williams equation for flow of water through pipelines. The loading pump performance characteristics were also evaluated by comparing the actual performance during pumping operation with the manufacturer's performance curve.

The pressure drops calculated for various flow rates and pipeline configurations using the model equation were in agreement with results obtained using the three methods listed above with a maximum pressure difference of about ± 25 psi. Evaluation of the pump performance showed the maximum mechanical efficiency as 79% compared to 89% originally specified by the manufacturer. The results of this work are applicable to designing pipelines based on actual field data. It is also useful for the periodic evaluation of pump performance.
Foam Rheology Characterization as a Tool for Predicting Pressures While Drilling Offshore Wells in UBD Conditions
Authors: Martins A. L. , Lourenço A. M. F. , Sá C. H. M. , Silva V.
Published: December 2007

The use of foam is a highly attractive alternative for drilling depleted, loss circulation or gas zones. Due to its complexity, a foamed system requires special attention while designing field operations.

This paper summarizes an extensive experimental program developed at PETROBRAS R&D Center facilities, coupled with a set of real scale tests under foam circulation conditions and numerical simulations, aiming the development of a comprehensive and useful model for predicting bore hole pressures while drilling under-balanced or near balance with foams.

The lab work steps include foaming agent selection, rheology lab equipment development and/or adaptation, definition of test procedure and matrix, besides discussion and analysis of results. After about 60 rheology tests performed in several lab and pilot scale equipment, correlations were proposed to predict rheological parameters as functions of foam quality. Based on the experimental data, a set of correlations was developed to predict foam rheological properties as functions of base fluid rheological properties and foam quality.

The next step was to evaluate the lab results by comparing pressure predictions with experimental data obtained by circulating different quality foams in a real scale vertical well located at PETROBRAS Training Center. The proper fitting of the proposed model and the experimental results supported its implementation in PETROBRAS lightweight fluid drilling software.
ROMEO: A New Powerful Tool for Drilling Rigs
Authors: Thomas S. , Cummins I. , Parfitt S.
Published: December 2007

This paper presents the new Integrated Mooring and Riser Analysis software developed by Noble Denton Europe Ltd. (NDE), called ROMEO. This software has been designed to be as useful a tool as possible for the management of drilling rig mooring and riser systems.

The theory behind the program is described and its use illustrated through an example study of a drilling rig operating in 6000ft of water.
Titanium Drill Pipe for Ultra-Deep and Deep Directional Drilling
Authors: Smith Jackie E. , Chandler R. Brett , Boster Patrick L.
Published: December 2007

This paper discusses the modeling and analysis of 5, 5-1/2, 5-7/8 and 6-5/8 in. titanium drill pipe in ultra-deep and deep directional drilling programs. Using a computer based drill string simulator, modeling a representative deep directional well, titanium drill strings were compared to the same size steel drill strings using two design criteria: margin of overpull and hydraulic efficiency.
Lateral Buckling of Pipe with Connectors in Curved Wellbores
Authors: Mitchell Robert F.
Published: December 2007

This paper brings together several buckling and pipe deformation analysis themes. Clearly, connectors should have an effect on the loading of pipe. For non-buckled pipe, Lubinski analyzed the effect of connectors on pipe in tension in a curved borehole and Paslay and Cernocky extended this analysis to pipe in compression. Connectors have an effect on the buckling of pipe, but the effect of connectors has only recently received attention. Three-dimensional helical buckling of pipes with connectors were analyzed by Mitchell, presented at SPE/AIDC 1999. Laterally buckled pipe with connectors was presented at SPE/AIDC 2000. In these papers, analytic solutions of the beam-column equations were developed in three-dimensions, and critical loads for buckling initiation were determined. Conditions for positive contact forces were determined and compared to previous buckling criteria, such as Paslay-Dawson.

In this paper, the wellbore curvature effects studied by Lubinski, Paslay, and Cernocky are included in the buckling effects studied by Mitchell. The modifications necessary to the analysis of lateral buckling are made for a curved wellbore. The resulting model gives a buckling criterion similar to He and Killingstad's results for pipe without connectors. The buckling model is integrated with the Paslay-Cernocky analysis to resolve some of the odd bending stress results developed by their model. Pipe deflections, contact loads, and bending stresses are determined with explicit formulas. Sag between connectors is calculated so that pipe body contact with the wellbore between connectors can be determined. Conditions for positive contact forces are determined and compared to previous buckling criteria, such as Paslay-Dawson and He-Kyllingstad.

Applications include the analysis of bottom hole assemblies, drill pipe, casing, and tubing. The solutions are simple formulas that are suitable for hand calculations.
Successful Application of MMH Fluid to Drill in Narrow Pressure Window, Ultra Deepwater Situation. A Case History
Authors: Fraser L. J. , Aragão A. F. L.
Published: December 2007

A mixed metal oxy hydroxide (MMH-type) system, which exhibits unique flow and gelation characteristics, was used to successfully drill an ultra deepwater well offshore Brasil. Despite ECD values that exceeded the measured leak off pressure and the calculated fracture threshold for the shale, no losses of fluid to the formation were reported. Subsequently rheological investigations of laboratory-prepared and field fluids were carried out under temperature and pressure conditions similar to those encountered on the subject well. The study unveiled unusual temperature responses of some key rheological measurements. This phenomenon may have played a part in the successful completion of the application discussed. Further work is being undertaken to better understand both this phenomenon and its implications for field application.

This paper discusses the development and application of the MMH fluid that is now a real alternative for the operator in deepwater applications where narrow pressure window circumstances have to be addressed.
Case History: Drilling Techniques Used in Successful Redevelopment of Low Pressure H2S Gas Carbonate Formation
Authors: Kinchen D. , Peavy M. A. , Brookey T. , Rhodes D.
Published: December 2007

This paper will provide a case study of the evolution of the drilling systems and techniques used to redevelop a dolomite formation located in the Indian Basin Field, Eddy County, New Mexico, USA. This study will compare data on wells drilled by Kerr-McGee over the past five years in this field where gas productivity ranges from 1000 MCFPD to 10,0000 MCFPD per well from the Upper Pennsylvanian (U. Penn) Cisco and Canyon formation.

The following drilling fluid systems utilized to drill 16 subject wells will be discussed:

Conventional

Four wells were drilled using conventional water based drilling fluids. When mud loss was encountered in the U. Penn, lost circulation materials (LCM) were used to regain and/or maintain circulation.

Drilling "blind" or "dry"

Two wells were drilled with this modification of the conventional system. Once returns were lost, an initial attempt was made to regain returns with LCM pills. If this did not restore returns, fresh water was pumped down the drill string to keep the bit face cleaned and drilling would proceed to total depth.

Air/Mist

Three wells were drilled using this medium. A string of casing was set prior to drilling into the U. Penn. An air/mist system was then utilized to drill to total depth. The well was completed open hole.

"Aphron" drilling fluid

This method was similar to the conventional drilling operation, but the drilling fluid system was converted to an "energized air bubble" mud system prior to drilling into the main pay. A total of seven wells were drilled with this system.
Using Multi-Function Fishing Tool Strings to Improve Efficiency and Economics of Deepwater Plug and Abandonment Operations
Authors: Going Walter S. , Haughton David
Published: December 2007

This paper discusses procedures and tool systems developed to optimize the efficiencies and economics of subsea plug and abandonment (P&A) operations. The tools and techniques described in the paper address removal of intermediate casing strings and final removal of the subsea wellhead. Included in the discussion is a new deepwater plug and abandonment system that employs a string of multi-function fishing tools that work cooperatively to minimize the number of trips required for casing and wellhead recovery (significantly reduce pipe-cutting time) and prevent wellhead damage without the use of motors.

Before the development of multi-function fishing tools, recovering a subsea wellhead required three or more drillpipe trips to remove each string of intermediate casing. This was followed by another trip to cut and recover the wellhead. During the 1990s, cut-and-pull technology consolidated cutting and recovery of the wellhead into a one-trip procedure. However, multiple trips were still required for each intermediate casing string. Given today's rig rates for deepwater work and the amount of time required to cut the large-diameter, thick-walled casing that ties into subsea wellheads, it is easy to see why any opportunity to improve the efficiencies of subsea P&A operations is welcome. The new systems and procedures addressed in this paper rely on proven technology to reduce risk and minimize field training required for successful deployment.

This paper compares time and costs for old and new methods. It describes a universal wellhead retrieval system and a unique procedural sequence in which casing is cut before seals are extracted. The system results in the ability to cut and recover the wellhead in a single trip without damaging the wellhead. The paper explains the safety, environmental, and economic advantages of eliminating motors and explosives and cutting the wellhead in tension. Case histories quantify results obtained in deepwater operations in the Gulf of Mexico and West Africa.
Continuous Direction and Inclination Measurements Revolutionize Real-Time Directional Drilling Decision-Making
Authors: Lesso William G. , Rezmer-Cooper Iain M. , Chau Minh
Published: December 2007

Strong economic and environmental pressures have led to the continued growth in the directional drilling business over the past few years. Parallel to this growth has been the complexity of the wells being drilled. These intricate trajectories have forced the development of more accurate sensors and surveying methods. However, directional drilling technology has not evolved rapidly enough to utilize the sophistication of the new measurements. Most directional drilling decisions are still based on traditional survey calculation methods, and regional knowledge concerning the behavior of the bottomhole assembly (BHA).

The use of conventional survey interpolation methods to determine well trajectories can conceal problems due to high doglegs and tortuosity that can lead to stuck pipe, missed targets, an inability to run casing, or may necessitate sidetracks,. High-speed transmission from measurement-while drilling tools can now take surveys in a near-continuous fashion. Therefore, direction and azimuthal information can be available every 2–3 ft while drilling. The continuous data, in addition to at-bit inclination measurements, contains rich information concerning the true nature of the wellbore tortuosity, and can be used to yield an accurate representation of the directional tendency of the BHA in both rotary and slide drilling modes, and may eventually make conventional survey measurements redundant.

A case study from the Gulf of Mexico highlights how the continuous direction and inclination measurements, and the surface and downhole drilling parameters, can be combined with a novel method to both calibrate and predict the directional tendency of a BHA in real-time. This methodology systematically reduces the ‘regionality’ in directional drilling operations, yielding the following: Early information concerning tool parameter settings for both conventional steerable and rotary-steerable drilling systems, for a more accurate approach to targets,Optimized slide/rotate sequences,Smoother wellbores, reducing torque and drag forces while drilling, and also minimizing the risk in running casing.
Innovations in Reservoir Navigation
Authors: Coghill J. , Benefield M. , Poppitt A. , Skillings J.
Published: December 2007

In order to maximize recoverable reserves in both new marginal satellite developments and bypassed oil in mature fields it is vital that a horizontal wellbore is optimally positioned within the reservoir. Recent innovations in drilling technology, three dimensional (3-D) visualization and logging while drilling (LWD) sensors have been integrated into a Reservoir Navigation Service focusing on maximizing the value recovered from every geosteered well.
Trends in Shallow Sediment Pore Pressures – Deepwater Gulf of Mexico
Authors: Ostermeier R. M. , Pelletier J. H. , Winker C. D. , Nicholson J. W.
Published: December 2007

As part of the effort to understand the problem of shallow water flow (SWF) in the Gulf of Mexico (GOM), and to obtain data and develop design criteria for offshore production structures, geotechnical wells were drilled in several different prospects. These prospects cover a 200+ mile swath across the central deepwater GOM where SWF control problems have been experienced. In these wells, pore pressure measurements, as well as core and other in-situ measurements, were taken in the deepwater shallow sediments.

Key facts and observations from these measurements include the following: A majority of the pore pressure measurements were made in low permeability clay rich material, predominant in the shallow sediments. Some measurements were proximal to more permeable sand and silt zones. A few measurements were made in sandy/silty intervals.Where significant over-pressures were present they were found to begin at or very near the mudline, and to increase more-or-less linearly with depth below mudline (BML).Over-pressures in the shallow sediments of the central deepwater GOM are due primarily to rapid sedimentation rates generated by the Mississippi River depocenter. This is supported by the fact that measured over-pressures exhibit regional trends generally consistent with sedimentation rate.Regional trends in over-pressures are also correlative with drilling experience and the incidence and severity of shallow water flow (SWF) occurrences.The degree of over-pressuring is consistent with sediment porosity based on core measurements, i.e., higher over-pressures are associated with higher porosities.There are exceptions to these general regional trends. Most notable is that over-pressures in shallow permeable sand or silt zones may not be in equilibrium with their bounding shales. Both pressure depletion and hyper-pressuring have been observed in the geotechnical-well pore pressure measurements and in drilling operations. Thus well location (up dip, down dip), faulting, fracturing and other factors need to be considered in predicting pore pressures in these permeable zones.
Successful Sealing of Vent Flows with Ultra-Low-Rate Cement Squeeze Technique
Authors: Slater H. J. , Stiles D. A. , Chmilowski W.
Published: December 2007

In the western Canadian sedimentary basin, tens-of-thousands of wells currently are leaking gas between the surface and production casings. Often this leakage manifests itself as a surface vent. While much work has gone into preventing gas vents during primary cementing, little has been done to improve the chances of successfully sealing existing leaking wells. The work described in this paper focuses on new materials and techniques that have been developed to seal vent flows. The paper describes the theoretical physics behind the process and gives case histories to demonstrate the successful application of the technology.
Pride Africa - Successful BOP and Riser Recovery Offshore Angola
Authors: Contarini P. , Zanchetta A. , Jeannet P. , Choquet M. , Sauteron D. , Puyaubran J. L. , Duhen T.
Published: December 2007

On the well JACINTO 01 (Angola), by 1 632 m of water depth, while pulling out the BOP stack to check a malfunction during the pressure tests of these BOP, before starting the17"1/2 phase, the breaking of the drilling line, while the BOP was at 620 m, caused the fall of the BOP and about 600 m of riser. The top drive felt and passed through the rotary table and, some other parts (bails, balls back-up wrench, elevator, riser running tool and few other metal debris) felt on the seabed with the BOP and the riser.The vessel returned to Cape Town for repair, inspections and preparation of the BOP recovery. In accordance with specialized service companies, we decided to try to recover it and we prepared tools:

For Example : ➩Lasso tool, Pride design➩Modified riser running tools➩Use of excavators➩Special jet subs with different designs …

The BOP recovery operation program, that will be developed in the presentation, is: Installation of a protection cage on well headRecovery of metal debris around BOPRecovery of laying riser joints by using jet tools, lasso tools…Excavation around BOP using excavators, jet tools …Cutting first riserFishing BOP using two strings in the same time…

The operation ended in success on the 26/01/2000, the entire BOP and the risers has been recovered.
Key Elements in Ultra-Deep Water Drilling Riser Management
Authors: Brekke James N.
Published: December 2007

Understanding the response of the drilling riser in ultra-deep water is critical for effective riser management and successful drilling operations. Due to the relative shortage of industry experience in ultra-deep water, analysis conducted prior to an operation is a key supplement to judgement and common sense. Damage or loss of the riser or the BOP leads to high costs for riser replacement and rig downtime.

The riser can be subjected to various loading configurations during a drilling operation. Storms and/or high current conditions can be encountered while the riser is in the following configurations: deployment; connected and tensioned; subjected to vessel drift-off; subjected to recoil after an emergency disconnect; and suspended in a hang-off condition. The unique aspects of each of these riser loading configurations in ultra-deep water warrant careful attention by riser analysts to provide operations personnel with well-founded guidance and an idea of what to expect in the field.

This paper provides an overview of the key elements of drilling riser analysis in ultra-deep waters. Analysis results are presented on the topics listed above, along with operational applications for several ultra-deep water drill ships. Shortcomings and uncertainties in riser analysis are discussed. The results show that analysis of key drilling riser configurations is critical for understanding riser response during operations and effective riser management.
Meeting Future Drilling Planning and Decision Support Requirements: A New Drilling Simulator
Authors: Booth J. , Bradford I. D. R. , Cook J. M. , Dowell J. D. , Ritchie G. , Tuddenham I.
Published: December 2007

Minimizing the cost of wells and the associated risk requires that construction techniques be optimized as rapidly as possible. This is a demanding task, particularly in an environment where fewer, higher value, more difficult wells will be drilled; it also necessitates a significant strengthening of drilling planning and decision support capabilities.

This paper presents an automated process for integrating well planning and real-time decision support. The process is encapsulated in a prototype software drilling simulator and incorporates recently developed real-time wellbore stability1and rate of penetration optimization modules. The simulator has three key features: Allows drilling practices to be closely linked with geological models.Provides a framework which integrates previously standalone aspects of drilling planning and decision support.Uses visualization techniques to convey complex models and results simply; this is a known driver of improved drilling performance2.

Examples illustrate the value of this integrated drilling planning and decision support tool.
Delivering Exceptional Performance in the Ketch Field
Authors: Hashmi N. A. , Foy John , Kohnert Jorg
Published: December 2007

The Ketch Field comprises a Carboniferous gas reservoir located in block 44/28 in the Southern North Sea. The reservoir section comprises fluvial depositional sand stringers inter-bedded with Shales, Halites and Coals.

The Ketch reservoir is overlain with the Zechstein evaporite sequence – Halites, Dolomites, Carbonates and Anhydrites, which makes drilling challenging due to significant well control problems. In particular, large quantities of highly mobile Potassium and Magnesium salts are present within the Zechstein Halites, which are responsible for brine flows into the well; which result in magnesium contamination of the drilling mud and considerable washing out of the wellbore. Within the Halite bodies, Anhydrite / Halite rafts exist, which the potential to contain gas/brine pockets, at pressures up to that of the overburden.

The Ketch project required four wells to be jack-up drilled from a Normally Unmanned Installation. This project was executed with Shell U.K. Exploration and Production (Shell Expro) as Operator, Maersk as drilling contractor with the Maersk Enhancer, and Santa Fe Techserv as Lead Well Engineering contractor. To drill the wells efficiently, the well design and execution was conducted under a Technical Limit ethos and philosophy.

The technical limit philosophy constituted to three main components of success: Calculating and identifying the Technical Limit time for each phase of the well, in an effort to create the theoretical maximum performance for the given well type in a given environment.Re-education of ALL team members on objectives and well delivery, enabling and allowing challenge by any team member at every stage of the process.Execution, monitoring and evolution of improvements which will take the team to the Technical Limit summit.

The conceptual design for the Ketch wells had been conducted in 1997. The wells were based on the Southern North Sea slim hole design with a contingency string if a high pressure zone was encountered in the Zechstein sequence. Each of the four wells to be drilled, did have their own identified risks, given the geological history of drilling in the Southern North Sea, but these risks added to the challenge to be overcome, by applying the Technical Limit concept.
A New Approach to Sidetrack Drilling of Marginal Wells Offshore
Authors: Weatherl Michael H. , Hardy Jack
Published: December 2007

During the summer of 1998 many efforts were under way to improve business results for operators in the U. S. Gulf of Mexico. In particular, an effort was undertaken by Chevron's Gulf of Mexico Shelf Business Unit which involved setting up a group of "technology brokers" to accelerate the application of new technology and innovation to improve profitability. Six Technology Brokers with multi-disciplined backgrounds were selected, and began to interface with field management teams across the entire Gulf of Mexico Continental Shelf. One of the major opportunities identified in the early stages of the Technology Broker effort focused on finding a faster and more cost effective method to sidetrack wells from offshore platforms.

The operator recognized that there were numerous, perhaps hundreds, of sidetrack candidates adjacent to existing platforms offshore which were marginal, or uneconomic using conventional methods. These "marginal" prospects had, in many cases, had been identified for years. However, they had always been marginal or uneconomic; i.e. when oil and gas prices go up, rig rates go up and the wells are marginal; when oil prices go down, rig rates go down, and again, the wells are not economically attractive.

The more the idea was researched, it became clear that if a faster and more cost effective sidetrack approach could be developed for these types of wells, the upside could add up to tens of millions of barrels. A project strategy was developed using decision analysis and organizational learning principles(1). This project became know as the "DESSERT Project". "DESSERT" is an acronym that was coined from the phrase, "Development of Small Reserve Targets".

This paper describes the DESSERT Project and the efforts over the last two years to develop a faster and more cost effective approach to sidetrack drilling of marginal wells offshore. Results, which include a new rig concept and significant cost savings, will be summarized.
Identification of High-Permeability Dolomitized Zones Using Inelastic Magnesium Yield
Authors: Hemingway James , Doi Manabu , Adani Nabeel
Published: December 2007

Massive carbonate formations that appear homogeneous over a large vertical interval on conventional openhole wireline logs may actually have permeability that varies by several orders of magnitude. Such was the case for a reservoir in a thick middle Cretaceous carbonate formation in the Arabian Gulf. Production performance indicated the presence of a very high permeability, or "Super K," zone in the reservoir. Identification of this zone and an evaluation of its geometry were crucial for efficient development of the field, which required an enhanced oil recovery (EOR) scheme to compensate for insufficient natural driving forces.

The zone was correlated with dolomitization in the carbonate reservoir, providing details on location, geometry and generation mechanism. The correlation was based on the knowledge that replacement of calcium with magnesium in the dolomitization process causes a slight shrinkage and resulting microfracture systems, which thereby significantly increase bulk permeability.

Recent developments in full-spectrum PNS measurements have made the direct detection of magnesium possible based on a very pronounced low energy peak in the inelastic gamma ray spectrum. This direct measurement of magnesium enables us to quantify the volume of dolomite within the carbonate formation in a cased hole or openhole environment and to adequately characterize rock properties, which are essential for the establishment of the future development scheme.
A New Interpretation Model Using Nuclear Magnetic Resonance Log for Micritic Reservoirs
Authors: Asakura Shigeaki , Hitoshi Takezaki , Miwa Masahiro , Kobayashi Osamu , Suzuki Masayoshi , Nishi Masatoshi
Published: December 2007

The Creataceous Thamama Group, offshore Abu Dhabi consists in part of fine-grained micritic limestone reservoir zones. Recent studies revealed that even the low resistivity zones could produce oil. Production from such zones has been confirmed by extensive core studies and production tests. It is the case that in these reservoirs the traditional Archies equation does not provide realistic water saturation results because of the dominance of the micrite particle, which has a complicated combination of pore systems such as the Micro pore, Mezo pore and Macro pore. In fact, the water saturation derived from the traditional Archies equations differs from the one obtained from TDT† and RST† measurements, which are independent from Archies theory.

In this paper, the Nuclear Magnetic Resonance Logging Tool (CMR†) has been employed to characterize the pore system of the micritic limestone reservoirs, and a new water saturation equation has been constructed so as to provide results consistent results with other information such as the core analysis and production tests.

The objectives of this study are:To characterize the pore system using CMR LoggingTo construct the new saturation equation based on the triple pore system, which is an extension of the Dual Porosity ModelTo re-evaluate the permeability estimator based on the model
Next-Generation Visualization Technologies for Exploration & Production
Authors: Zamel N. M. , Pita J. A. , Dogru A. H.
Published: December 2007

The rapid advance of parallel computing technology has made it possible to perform geoscience and engineering analysis with unprecedented speed and accuracy. From seismic pre stack depth migration to multi-million cell reservoir simulation, the ability to solve petroleum technology problems with more detail and fewer approximations in less time has impacted and will continue to impact our business for years to come.

Just a few years ago, reservoir models consisted of orders of magnitude more cells than could be handled by the most advanced simulators. With the existence of simulators capable of handling mega-cell models, geological detail need no longer be compromised by intensive upscaling. In addition, the increase in resolution of seismic data and use of multi-attributes to predict reservoir properties is yielding images of the subsurface to a level of detail once considered unattainable.

These new capabilities bring considerable opportunities to improve our productivity. More than ever, our data possesses tremendous value that we can now harness by sophisticated algorithms and teraflop computing power. However, our ability to visually analyze this amount of information has not kept pace with these advances. We now use stereographic images to better understand reservoir continuity but we still use a 2D mouse for manipulating this information. Only very recently, devices that function as a "3D mouse" with the ability to edit 3D models have appeared. Feedback reinforcement using audio cues is also being utilized.

Immersive visualariums enable multidisciplinary teams to discuss field development scenarios in activities such as planning "virtual" wells before expensive errors are made in the field. However, the amount of data still offers a challenge even to the most advanced visualization systems. And we still need to create a remote collaboration model to bring together data and expertise residing in different locations.
Effective Pressure Formulation for Gas Well Test Analysis
Authors: Metnani Mabruk
Published: December 2007

An effective pressure "p/z" formulation is proposed as an alternative to the classical pseudo-pressure approach used in gas well test analysis, suggesting that the complexity of an integral transformation may not be needed in the analysis. The performance of the new formulation is cross-checked against the three traditional approaches of pressure, pressure-squared and pseudo-pressure formulations using a reference non-linear numerical pressure solution as a benchmark test. Results of the simulation show that the method predicts flow capacity with a higher level of accuracy in comparison to other formulations, even for extreme pressure drawdown beyond what is usually experienced in well testing. In addition, the p/z formulation has special merits due to the fact that it is a direct measure of gas density, is simpler to apply in practice than the frequently-used pseudo-pressure and last but not least, it is consistent with the classical gas material balance formulation, which can be considered a special solution form of the same gas flow equations.
Effective Permeability Estimation for Modeling Naturally Fractured Reservoirs
Authors: Nakashima T. , Arihara N. , Sutopo Sutopo , Sato K.
Published: December 2007

Three different methods, the discrete fracture, dual and single continuum approaches, are currently used for simulation of naturally fractured reservoirs. A dual porosity or dual permeability approach is applied in simulation when fractures are well developed to form a flow network. On the other hand, the single continuum model, where the fracture system is represented by effective permeability, is commonly used if fractures are discrete or disconnected. Focusing on the latter case, this paper addresses several issues for characterizing naturally fractured reservoirs: an effective approach to determine equivalent or effective permeability tensors, the representative elementary volume (REV) for effective permeability determination, and applications of the permeability tensor to flow simulation.

The complex variable boundary element method is used to compute potential field and streamlines in two-dimensional fracture systems under the periodic boundary conditions. The complex potential at a point is expressed as summation of potentials for matrix, fractures, and fracture intersections. The fracture system is assumed to comprise infinitely thin fractures of infinite conductivity, and allowed to include discrete or intersected fractures.

Effective permeabilities calculated for stochastic fracture distributions are correlated with the fracture geometric parameters: the total length, the mean length, and the mean orientation angle. Effects of length and orientation variations are minor, and can be ignored. Non-parametric regression shows roughly equal levels of influence of the geometric parameters on both diagonal and off-diagonal elements of the permeability tensors. A REV study for stochastic distributions demonstrates behavior of effective permeability depending upon the area of the effective permeability calculations. Effective permeabilities estimated for regional fracture type systems show a strong effect of the fracture intersections of which flow potential reduces the diagonal elements of the effective permeability tensors. Finally, the effective permeabilities are applied to a simulation model to calculate tracer propagation.
Use of Short Radius Horizontal Recompletions to Recover Un-Swept Oil in a Maturing Giant Field
Authors: AL-Jandal A. A. , Farooqui M. A.
Published: December 2007

This study evaluates the performance of short radius horizontal (SRH) wells in a giant field in Saudi Arabia. The objective of these SRH recompletions was to reactivate the wells that were dead due to excessive water production from an advancing flood front. The paper discusses factors contributing to success or failure in meeting the objective and compares the performance with the vertical dead wells that were plugged-back with a mechanical plug to reduce water production and to enliven them.

This study concludes that sidetracking dead wells and re-completing them in a relatively thin, upper section of the reservoir is an economically viable strategy to target the remaining oil. The productive life of short radius horizontal wells was found to be longer than that of vertical wells that were plugged back with a mechanical barrier in the wellbore.
Where are we from the Downhole Scale Problem
Authors: Darwish Sameh F. , Abdel Aziz Hany M. , Abdeen Fathalla M.
Published: December 2007

Downhole scale deposition in producing wellbores is becoming a serious problem to most of the Egyptian Petroleum Companies. With the increase in water production from depleted reservoirs the problem is escalating. For those companies that are using water flooding to maintain the reservoir pressure the problem is greater as the scale is often calcium, barium and strontium sulphates, which are acid insoluble.

The options for scale removal range from a full rig work over to replace the production tubing to a brush run on slick line. Often tubing treatments using coiled tubing is advantageous due to saving compared to rig cost.

The paper presents cases for conventional chemical treatment using hydrochloric acid and applying organic dissolvers (chelants), where the scale is not tolerant to acid, insoluble. Also conventional solutions for mechanical removal, an impact hammer with a mill or pure liquid jetting techniques will be included.

As the paper title is in a form of a question, it will also answer a lot of questions, based on the case history results as :⋄Why scales are formed in those wells having very low water cut (trace-3% vol.)?⋄Why the organic dissolvers prolong the scale deposition lifetime? Do they have inhibition effect?⋄Why the lifetime of scale re-deposition is very short after acid cleaning, and sometime the full production loss is experienced?⋄Why there is a great discrepancy in the inhibition life time (Few months-3 years) for the different wells in the same field?⋄What is the most effective programs to be implemented for the downhole scale problem?⋄What are the most reliable field techniques for scale deposition and scale inhibitor jobs efficiency monitoring?
Estimation of Skin for High Deliverability Gas Well Tests
Authors: Elshahawi Hani M. , Gad Khaled H.
Published: December 2007

In general, any restriction to flow that causes a distortion of the flow lines from being perfectly normal to the borehole direction would result in positive skin. As a result, the skin factor computed from well testing is a widely used indicator of the overall flow efficiency of a given well. This is theoretically valid, but often, a high positive skin indicated from a well test is assumed synonymous with a large extent of near-wellbore formation damage and is, therefore, frequently used as a criterion to perform stimulation treatment meant to enhance the well productivity. This latter practice is generally not valid since the skin factor computed from a well test is, in reality, a composite variable that is not merely a function of near-wellbore damage. This skin factor is also a function of parameters such as perforation geometry, well deviation, partial completion, and other phase and rate dependent effects. Therefore, the skin computed from a well test must first be broken down into its constituent components in order to determine the "true" near-wellbore skin. Moreover, the skin and permeability values computed from a well test are so intimately related that an error in one directly impacts the other. Typically, additional input data would also need to be integrated in any given permeability-skin model in order to reduce the computational uncertainty. Only after proper modeling, can an appropriate stimulation treatment be selected. This is particularly important for high-deliverability gas wells, for which the formation damage-related skin often makes up only a small portion of the total well test-measured skin.

This paper outlines a methodology that can be used to compute the various skin components as well as representative values of the average formation permeability from a well test. Several examples from gas wells are presented to demonstrate the utility of this methodology.
How Data-Driven Modeling Methods Like Neural Networks can Help to Integrate Different Types of Data into Reservoir Management
Authors: Stundner M. , Al-Thuwaini J. S.
Published: December 2007

Additionally to proven deterministic modeling techniques, like numerical reservoir simulation, so called "data-driven" modeling techniques can support petroleum engineers in reservoir management tasks.

Data-driven modeling means that the underlying relationship among measured data is calculated by the model itself and no a priori knowledge of the physical system governing the data behavior is needed.

Neural Networks are such data-driven models and "learn" the underlying model from data. Neural Networks are computational models broadly inspired by the organization of the human brain. The most important features of a Neural Network are its abilities to learn, to associate, and to be error-tolerant.

Many papers have been published during the last years demonstrating the wide range of possible applications of Neural Networks in Exploration & Production. An example in reservoir management issues will be presented, with regard to optimizing the injection-production ratio in a Middle East reservoir.
Accurate Prediction of Well Requirements in Gas Condensate Fields
Authors: Smits R. M. M. (Bob) , van der Post N. (Niko) , al Shaidi S. M. (Salman)
Published: December 2007

PDO have two deep gas/condensate producing fields that exhibit well impairment due to condensate build-up. Such a build-up can reduce well productivity with a factor of 3. Fraccing the wells will partly alleviate the impairment because of high initial production rates. However, accurate simulation of both the fracture (~50 m) and the condensate build-up requires fine grid simulations which are very time-consuming and inherently unstable. Originally fast coarse grid simulations were used. However, after having performed some finer grid simulations PDO noticed that impairment was a much bigger factor than was predicted by the coarse grid simulations, such that mid-term (1-5 years) condensate production would be lower than in the original assessment. Hence the field development plan based on the coarse grid simulations might not be sufficient to obtain the planned production. To enable a better prediction, involving many simulation runs, a fast but accurate simulation scheme was required.

To solve the above problem we have developed the following integrated approach to model gas/condensate field performance.Model liquids are used for the laboratory relative permeability measurements.More accurate implementation of the condensate build-up in the full field simulation models (for fracced wells) was achieved by ‘pseudoing’ the gas inflow. This method allows the use of coarse grid blocks (300x300m) while still correctly describing the condensate bank around the fracced wells.Long term well test analyses were used to boost confidence in the models and to calibrate them, where necessary.

The main advantage – in addition to more accurately describing the field performance – is that the above method allows 20 years full field forecasts to be done within 4 hours computing time.

Therefore, the above framework has provided PDO with a tool to obtain a much more accurate field development plan.
The in Salah Gas Project, Central Algeria: Bringing an Eight Field Gas Development to Sanction
Authors: Davis Neil , Riddiford Fred , Bishop Clive , Taylor Brian , Froukhi Rachid
Published: December 2007

In Salah Gas is a joint venture between Sonatrach and BP that will deliver 9 billion cubic metres per annum (bcm/a) from eight gas discoveries in the Ahnet-Timimoun Basin of Central Algeria. Prior to the sanction of this project in early 2000 an exploration and appraisal programme was completed to reduce uncertainty in gas volumes and deliverability, prove additional reserves and demonstrate commerciality of the development.

Uncertainties were identified and ranked by quantitative assessment of alternative appraisal options and their impact on project value (Value of Data analysis). The analysis was used to help define objectives for the exploration and appraisal programme that comprised acquisition of 2D and 3D seismic data plus the drilling of 9 wells.

Key objectives of the appraisal activity were to assess the connectivity of conventional Devonian reservoir intervals, evaluate tight gas reservoirs, assess the contribution of fractures to well deliverability and gain an understanding of Carboniferous reservoir distribution using 3-D seismic imaging. 4 Extended Well Tests (EWT’s) were a key part of this programme.

Optimisation of the exploitation and sequencing of the 7 fields’ development led to significant cost savings. A modelling tool jointly developed by facilities, wells and subsurface teams ran multiple development options providing ranked options with deliverability assurance.

As part of Sonatrach and BP’s commitment to reduce greenhouse gas emissions, the vast proportion of produced CO2 (400Bcf) will be re-injected at the cost of the project. Two or three dedicated horizontal wells will be drilled to dispose of the CO2 and infrastructure will be put in place to facilitate disposal of CO2 from all eight fields.
The Feasibility of Using Time-Lapse 3D Seismic to Monitor Fluid Displacements in an Abu Dhabi Onshore Oil Field
Authors: Kleiss Erik , Melville Peter , Al-Jeelani Abu Baker
Published: December 2007

Time-lapse or '4D' seismic has been used to directly monitor the fluid movements in some oil- and gas-reservoirs. This technique allows one to verify and where necessary to update the reservoir flow models, e.g. to incorporate 'geological surprises' like unexpected flow barriers or conduits. The method is based on the change of the acoustic properties (velocity, density) of the reservoir when the initial reservoir fluid in place (oil, gas, brine) is replaced by others while the reservoir is produced. Under favourable conditions this change in properties leads to a detectable change in the seismic reflection.

Successes of 4D seismic have been reported, mostly from clastic reservoirs located offshore and onshore heavy-oil/tar sands reservoirs. In such reservoirs the change in seismic response with changes in reservoir fluid is relatively large. Direct hydrocarbon indicators, AVO and bright spots often work well in these reservoir types. Furthermore the good quality of modern 3D marine seismic data allows one to reliably detect these changes in many offshore cases.

For the large onshore oil fields produced by ADCO, the situation is more challenging. The main reservoirs are formed by fairly hard carbonates; they are reasonably deep and consist of several thin zones with quite different flow properties due to variable porosity, permeability and fracturing. The surface is covered by sand dunes, which severely hamper the recording of high quality recorded seismic data. Some oil fields have been producing for more than 30 years and have been penetrated by several hundreds of wells, including infill horizontal drilling. However, the reservoir behaviour is still not fully predictable and sometimes wells do not perform as expected. With extensive use of water-injection for production support and gas-injection programs scheduled, a further calibration and refinement of the reservoir models would be quite welcome. The recent improvements in the quality of 3D seismic data seen in Abu Dhabi could enable the successful application of 4D seismic (and its associated benefits) for these fields.