bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delivering Exceptional Performance in the Ketch Field
Authors: Hashmi N. A. , Foy John , Kohnert Jorg 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.