bluuebunny/crossref_metadata_2025 huggingface dataset:
New Norwegian HSE Standard for the Offshore Industry
Authors: Huse Jan Reier
Published: December 2007

NORSOK (The competitive standing of the Norwegian offshore sector ) is the Norwegian industry initiative to add value, reduce cost and lead time and remove unnecessary activities in offshore field developments and operations.

The NORSOK standards are developed by the Norwegian petroleum industry as a part of the NORSOK initiative and are jointly issued by the Norwegian Oil Industry Association and the Federation of Norwegian Engineering Industries.

The purpose of the industry standard is to replace the individual oil company specifications for use in existing and future petroleum industry developments, subject to the individual company's review and application.

The NORSOK Health, Safety and Environment (HSE) standards covers: -Technical Safety,-Working Environment,-Environmental Care,-HSE during Construction.

The standards are now being used in ongoing offshore development projects, and the experience with standards shows that the principle aim is being met. The development of standards continues, implementing experience gained.
Environmental and Safety Audits - A Process to Improve Business Performance
Authors: Brommelsiek William A. , Tinsley Kirk T.
Published: December 2007

For a number of years numerous organizations have utilized environmental and safety compliance audits to verily that facilities and operations were meeting legal and company requirements. Historically these audits have focused on ensuring that regulatory standards, permit conditions, company standards, etc., were being achieved. In some companies the focus of internal audits is moving away from compliance to an evaluation of the management systems and work processes that lead to improved environmental and safety performance in concert with improved business performance.

This paper discusses this evolution within a U S. Business Unit of an international oil and gas company. A process for the management of these audits at both a facility and business unit level will be presented. The benefits of periodic reviews focused on the environmental and safety management systems and work processes within an organization in identifying both deficiencies and ‘best practices" will be demonstrated. It will also be shown that improvements in environmental and safety performance, as measured by both safety and environmental performance metrics, can contribute to improved business performance in terms of reduced operating costs.
Decision Making in Offshore Emergencies: Are Standard Operating Procedures the Solution?
Authors: Skriver Jan , Flin Rhona H.
Published: December 2007

Emergency situations on offshore installations can have devastating effects as seen in the Piper Alpha disaster in 1988. Offshore installations in the North Sea can be situated more than 100 miles from the coast and it is therefore imperative that personnel have the ability and facilities to deal with an emergency on their own. The offshore installation manager (OIM) is responsible for handling an incident which is likely to be characterised by time pressure, high risk, ambiguous information, unclear goals, and constantly changing conditions. To help the OIM, standard operating procedures (SOPs) have been introduced by the operating companies, which provide a set of rules to apply in a given crisis. At present there is a trend towards creating SOPs for every predictable offshore crisis. A constant increase in the number of procedures, generated to cover every eventuality, may obviate the need for OIM decision making but also create a problem if a novel emergency is encountered. Moreover, there may be dangers associated with too great a reliance on SOPs as they may become hard and fast rules that must be followed blindly. It is therefore of interest to identify how SOPs are utilised and what knowledge underpins their use. This research is based on interviews with 10 experienced OlMs on UKCS platforms from one major operator. It suggests that experienced OlMs have a repertoire of standard responses which they can apply in a crisis. This intimate knowledge of the emergency procedures has been developed through regular exercises, onshore simulator training, and involvement in the maintenance and improvement of the safety management systems on their installations. That is, decision making in offshore emergencies appears to be based on sound foundations, not on blind application of rules. A comparison is drawn between the decision making of the OIM and that of other emergency commanders, with particular reference to current theories of naturalistic decision making. Implications for OIM training are discussed.
A New Approach to Develop Petroleum Engineering Software
Authors: Xiong Hongjie , Rahim Zillur , Holditch Stephen A. , Lancaster David E.
Published: December 2007

In this paper, we present a new approach to software development for solving engineering problems. The paper presents the possible solutions to the problems that we encounter during the development of engineering software where we incorporate different techniques and tools such as a database, case base, knowledge base, expert help, on-line help, multiple-applications, and guidance board/map. The paper also discusses the reusability of code that is derived for a different application. Finally, the paper illustrates how we use this approach to develop a comprehensive software system.

The paper concludes that engineering software must be versatile in nature. The software should be a working tool for industry experts and experienced engineers. The software should also be a training and learning tool for young and inexperienced engineers.
Experimental Design in Interactive Reservoir Simulation
Authors: Faidi S. A. , Ponting D. K. , Eagling T. L.
Published: December 2007

The existence of multiple processors on a network or a parallel machine enables sets of reservoir simulations to be performed. It is then possible to build up a model of the reservoir as a response surface. This can be a function of input variables related to symbols in the user's data definition. Controlling these variables by a master program and using experimental design methods in a series of runs we can model the behavior of the simulation. This would then predict its response to further engineering requests. Sequential designs are particularly relevant when a bank of available processors exists. Once the basic number of runs required to parameterize the reservoir response functions have been performed, additional simulations may be used to obtain error bars on quantities such as recoverable oil.

Once the response surface exists, both automatic optimization and large scale risk analysis predictions may be performed at high speed.

This approach combines well with multiple realization geological modeling. Running a number of geologies enables the error involved in the simulation of a given engineering scenario to be quantified - this can be used to predict the uncertainty on all the predictions of the study.

By monitoring the results of the simulations interactively, and measuring the quality of the history match obtained with each, it is possible to condition subsequent runs - for example by reducing the use of realizations which consistently yield poor matches.

We describe software to perform such multiple realization studies, acting as an interactive supervisor through a simple open PVM (parallel virtual machine) interface to a reservoir simulator.
Application of Hazard and Effects Management Tools and links to the HSE Case
Authors: Gower-Jones A. D. , van der Graaf G. C. , Milne D. J.
Published: December 2007

Many tools and techniques are promoted for the analysis and management of hazards and their effects. The proliferation in the last 5-6 years of (hese tools has resulted in an overload on designers, engineers and operators of E&P activities and assets to the extent that they are unsure what to do when and how this fits together. This paper starts from the basic E&P business (a business model) the basic structure of any accidental event (bow tie) and maps the tools and techniques to analyse the hazards and effects for both asset and activity HSE management. The links to developing an HSE case within the HSE-MS for assets and activities are given.
Biological Cleaning of Soil and Reservoirs from Oil Products
Authors: Zinberg M. B. , Ivanovskaya I. B. , Gafarov N. A.
Published: December 2007

The production of oil and gas condensate invariably involves enviromental hazards: water and soil contamination due to miscellaneous breakdowns of technological equipment and pipeline damage. Among many existing contamination methods biological cleaning has become more popular lately.

It took us some years to make investigations and to carry out a number of field tests in order to develop biological methods of cleaning soil and reservoirs from oil and gas condensate products. Our method is based on the use of special biological agents containing various active hydrocarbon oxidizing bacteria. It has been experimentally proved that biological agents of "Devouroil" possess the greatest oxidizing properties. "Devouroil" contains five kinds of hydrocarbon oxidizing bacteria of Pseudomonas, Rodococcus, Candida genera. These bacteria are extracted from natural ecosystems: underground waters, soils, reservoirs. As the agents are grown on oil distillate, they are very destructive to different oil products. We also proved the described microorganisms' ability to oxidize sulfate oil and hydrocarbon condensate, which are the most toxic components. For four years our colleagues have been cleaning soil and reservoirs contaminated with oil, black oil, gas condensate and other products of hydrocarbon origin. This method was used to treat different kinds of soil and ground (grass and arable land, swamp and forest) in actual hazardous situations involving oil and gas condensate spills. Besides it was successfully applied to clean sludge storage which had been filled with oil process sewage for several years.

The efficiency of soil treatment depends on many factors: the age and degree of contamination, the depth and the type of polluted soil, climate. The cleaning effect of the proposed method proved 75-90% over the period of 2-3 months with initial pollution up to 150 g/kg, all the requires being fulfilled. The test results are represented in Table 1.
Bioprocess for Treating Coproduced Oily Sands
Authors: Munnecke D.M. , Ireland Jim
Published: December 2007

The production of oil from certain oil fields creates significant amounts of oily sand which in many regulatory jurisdictions is regulated as a hazardous material, thus disposal costs can be significant. Environmental BioTechnologies, Inc. (San Carlos, CA) has developed a physical/biological treatment process that is able to economically treat these coproduced sands and produce a product that contains less than 2,000 ppm total petroleum hydrocarbons.

Introduction

Production of crude oil from some reservoirs results in significant amounts of coproduced sand. This sand, once separated from the crude oil, still contains between 1–5% crude oil which limits disposal options and increase costs for those disposal process suitable for this hazardous waste. Environmental BioTechnologies, Inc. has developed a treatment process that can economically treat these oily sands and produce a treated product which has less than 2,000 ppm total petroleum hydrocarbons (TPH). This process, as diagrammed in Figure 1, involves three distinct treatment stages. In the first stage, the oily sand is collected and transported to a holding tank where sand, waste and oil are allowed to gravity separate. From the separation tank, the sand is washed with hot water to remove 75% of the crude oil, reducing the TPH concentrations to the 10,000 ppm range. A third process involves biopolishing to reduce the TPH levels to below 2,000 ppm.

Results

The key to this treatment process is the biological polishing step that reduces TPH concentrations to below 2,000 ppm thereby allowing the sand to be classified as a non hazardous waste (level varies depending on regional regulatory requirements) or byproduct. Treatment by chemical or physical process steps alone is not able to reach these low end treatment levels.

The rate of removal of crude oil in the biopolishing step is shown in Figure 2. TPH levels drop rapidly over the first 28 days of treatment, going from approximately 10,000 ppm to below 2,000 ppm in 28 days.

Conclusions

The combined physical and biological treatment process for oily sands is expected to be economical to alternative waste disposal processes in regions where oily sand is regulated as a hazardous material. If disposal costs are above $40.00 per cubic yard, then this treatment process is expected to lower treatment and disposal operational costs. The most economical application of the treatment technology is to construct treatment facilities in areas of oily sand production, Units can be designed for the specific volumes of oily sand generated by the oil production operation. The first step in evaluating this technology is to conduct a short biofeasibility laboratory study to determine the effectiveness of crude oil removal and biodegradation. With this information, we can then estimate how to design this process for a specific crude oil - sand waste and develop cost estimates. Subsequent actives would involve a field pilot demonstration and then full scale operation of the process.

P. 765
Utilization of Gas Satellites to Reduce Environmental Impact in the Cavalier Gas Field
Authors: Ogden Peter K. , Davies Colin , Ho Ki-Tat , Soo Edmond
Published: December 2007

There are significant benefits to utilizing gas satellites to reduce the environmental impact of gas field development as compared to having individual wellsite facilities. Potential economic gains and operational advantages associated with gas satellites can make the option attractive on a project specific basis.
A Review of the Concepts and Methodology of Determining "Net Pay"
Authors: Snyder Richard H.
Published: December 2007

A review of the methods of determining net pay in hydrocarbon-bearing reservoirs is presented with emphasis placed on the ultimate use of the net placed on the ultimate use of the net pay map; i.e., for determining total pay map; i.e., for determining total in-place hydrocarbons, for the determination of the total energy balance of the reservoir and evaluating secondary recovery prospects. The use of various logs, core data and test data are discussed in conjunction with calibration of the net pay. The concept of petrophysical cut-off values and approaches to their determination are illustrated. An idealized reservoir is mapped using net thickness, pore volume and hydrocarbon pore volume pore volume and hydrocarbon pore volume datums and the results compared. The results indicate that the mapping using these different datums are essentially compatible, dependent only on the intended usage of the maps. Volumetric calculations are also made and the results are compared and evaluated.

Introduction

One of the most misunderstood and poorly defined terms used in reservoir poorly defined terms used in reservoir geology and formation evaluation is the concept of net pay. The following discussion is an attempt to more precisely define this term, to demonstrate precisely define this term, to demonstrate methods of selecting net pay and show that the intended use of the net pay often determines how net pay is "picked". Several different systems of determining net pay thickness and mapping techniques for net intervals are illustrated using an example reservoir. Methods for calculating volumes of net pay from these different types of maps are also discussed and compared.
Thermal Well Casing Failure Analysis
Authors: Maharaj G.
Published: December 2007

Casing failures in steam injectors and cyclic steam wells have been encountered in old wells completed with low strength J55 casing as well as in new wells with higher grade N80 casing. Eighty five percent (85%) of the failures occurred at the coupling due to joint pullout or fracture caused by cyclical or rapid heating and cooling. Fifteen percent (15%) of the failures were due to buckling resulting from poorly cemented casing and low cement tops. Different techniques have been used to prevent casing failures: insulated tubing, packers and thermal cups. However, these were found to perform unreliably and did not achieve large scale implementation. There have been no failures in ten (10) wells completed with N80 buttress prestressed casing subjected to continuous and cyclic injection over the last five years.
Environmental Performance Indicators : A Survey of their Actual Use in the E&P Industry and of their Foreseeable Development
Authors: Garland E. , Thomas I.
Published: December 2007

Major industries or governmental bodies have developed Environmental Performance Indicators. Many oil and gas exploration and production companies started to use the measurements and data they gather as environmental performance indicators. The Oil Industry International Exploration and Production Forum organised a workshop on the subject in 94 and, subsequently, made a survey of their actual use in the E&P industry.

The results of this survey, conducted in 1995, are presented. They confirm the interest of companies for such indicators but also reveals difficulties inherent to their use. Proposals are made to improve that situation.
Modeling Fractured Reservoirs With Stochastic Fractals
Authors: Olarewaju Joseph
Published: December 2007

The aim of this paper is to present a method of building a heterogeneous reservoir permeability field for flow simulation using pressure transient data. The permeability field will be derived from effective permeability and fractal dimension obtained from well test analysis and conditional simulation techniques. The paper presents and discusses the different levels of heterogeneity that can be created with different values of the fractal exponent.

A mathematical model is presented for estimating effective permeability and fractal dimension from transient data from naturally fractured reservoir. This model is more appropriate than existing models because it considers the irregular and random nature of the fractured system in the reservoir matrix. The model is well suited for computer automated well test analysis.

An illustrative example of how to use effective permeability and fractal dimension derived from pressure transient test data with some reservoir data to generate consistent reservoir description is presented.

Introduction

The need to describe reservoir heterogeneity for flow simulation has been realized for many years. However, this has proved to be an almost impossible task because the required petrophysical properties are sampled at a few locations in the reservoir. Reservoir engineering practitioners often have to use constant or interpolated values for porosity and permeability in the simulations cells. Researchers have recently adopted the use of geostatistical techniques and reported favorable results in history matching field data. They have reported that the use of constant porosity and permeability or interpolated property fields lead to a highly optimistic sweep efficiencies and late breakthrough times of the injected fluid. The reason for this optimistic results in terms of breakthrough time and sweep efficiency is because of the absence of the heterogeneity that actually exist in the field. The appropriate high permeability channels and streaks that affects fluid channelling is absent in these constant or interpolated property models.

Improvements in reservoir characterization can yield major improvements in reservoir performance predictions but the sparseness of data makes this difficult. The fact that the measured data density is sparse has made the use of stochastic property fields rather more appealing than deterministic reservoir models. The idea behind the stochastic models is to construct property distributions of the reservoir that honor measured data at sampled locations using the correlation derived from the measured data and some conditional simulation algorithm.

The scarcity of data is even more serious for permeability which is the most important input data for the reservoir simulator. Usually, unlike porosity, this cannot be accurately derived from well logs. If cores are available, it may be possible to derive a good porosity versus core permeability transform. Most of the time this is not so, and the only data available may be pressure transient measurement from a few wells.

P. 352
Completion and Stimulation of Horizontal Wells in Yibal Carbonate Reservoir, Oman
Authors: Al-Bimani Atika , Veeken Kees , Brakel Jan , Sardar Khalid , Kapteijn Pieter
Published: December 2007

The Yibal carbonate reservoir in North Oman is developed using horizontal wells. The completion technique has evolved from open hole to cemented and perforated liner. In parallel, the stimulation technique developed from spotting small volumes of acid across barefoots to selective acid treatment of perforated liner sections.

This paper describes the completion and stimulation techniques and compares their production performance based on a 55 well data set.
Advanced Seismic Data Interpretation for Carbonate Targets Based on Optimised Processing Techniques
Authors: Fischer Klaus , Moller Ulrich , Marschall Roland
Published: December 2007

Advanced Seismic Data Interpretation for Carbonate Targets Based on Optimised Processing Techniques.

The Shuaiba Fm. represents one of the most prolific hydrocarbon reservoirs in Abu Dhabi. The remaining potential is supposed to be related to subtle structural and stratigraphic traps. New developments in exploration geophysics like prestack depth migration integrating processing and interpretation form a powerful tool for improved development of existing oil fields and for identification of new oil fields.

In general the processing comprises three phases (depending on the local validity/violation of the zero-offset (zo)-condition, i. e. to which extent does the DMO-stack represent a zo - volume):

Phase A: Standard processing sequence up to final DMO stack and migration including calibration using elastic instead of plane-wave synthetic seismogram. The interpretation team generates a first macro model of the velocity field.

Phase B: Poststack depth-domain

The velocity field is checked and updated using the wavefront method. The new macro model forms the basis for poststack depth migration, which is reinterpreted by the interpretation team in order to confirm / update the reflector geometry and to generate the final macro model required for

– Phase C: Prestack depth-domain.

The prestack depth migration is subject to final interpretation and - due to the irregular surface of the Shuaiba Fm. - should form the basis for AVO. Further steps are L-l- deconvolution followed by Born inversion, which is essential for generation of a high resolution lithological model.

The procedure is presented using a 2D seismic line, which was subject to a detailed interpretation (seismic sequence and facies analysis) of the Shuaiba Fm. The final result is a detailed lithological model which is verified by applying elastic forward modeling ("verification loop's"). The results are to be used as input in reservoir modeling and geostatistical evaluations in order to take into account reservoir heterogeneities being important for prospect evaluation.

Introduction

Geology and Stratigraphy of the Shuaiba Fm in Abu Dhabi. The shallow water carbonates of the Lower Cretaceous Shuaiba Fm (Upper Thamama Group, Aptian) was deposited on a vast shelf covering the eastern Arabian Peninsula. The formation of intrashelf basins resulted in the establishment of facies belts i. e.–shallow water shelf carbonates–a buildup prone belt rimming the intrashelf basin centered in Abu Dhabi and–basinal deposits in the intrashelf basin areas.

The shelf margin buildups - mainly rudist buildups - of the belt rimming the intrashelf basin today form the most prominent hydrocarbon reservoirs (Frost et. al., 1983). The shallow water shelf carbonates however may represent a potential reservoir due to increased porosity resulting from subarea exposure and weathering by meteoric waters during the Bab relative sealevel lowstand.

P. 730
The Accuracy of Cubic Equations of State for Composition Predictions
Authors: Abrishami Y. , Hatamian H.
Published: December 2007

Tuning of the equation of state have proven to be the most successful method for improving the performance of compositional reservoir simulators. The data used for this purpose are normally PVT laboratory measured values of overall fluid composition, densities and viscosities, together with saturation pressure and liquid dropout at the cell conditions. In the simulation of oil recovery processes, where changes in compositions and interphase mass transfer are dominant factors, the tuning should logically be based on matching with measured values of compositions rather than, or in addition to, the aforesaid values. This is even more essential in solvent injection simulations, where the overall composition of the fluid is continuously changing. Existing tuning techniques provide a degree of improvement, however, change of composition in solvent injection requires regression and tuning on the base of composition matches in a multiple contact process. In this work we have developed a computer programme for simulation of multiple contact gas injection process which has been used for reproducing some experimental values on composition in constant composition expansion and multiple gas injection tests. The Peng-Robinson equation of state is examined for matching the measured values.
3-D Seismic Data Acquisition in Offshore Congested Field
Authors: Belaid Kamal
Published: December 2007

This paper describes the techniques and strategy implemented by ADMA-OPCO in acquiring a successful and cost-effective 3-D seismic survey in a highly congested field located offshore Abu Dhabi. The early planning of the survey, the team work, the adequate data QC and the interaction between the three phases of data acquisition, processing and interpretation are highlighted as the key elements which granted the success of this survey. They contributed in achieving the technical objectives and addressing efficiently the logistical issues in a cost-effective manner.
Coiled Tubing Deformation Mechanics: Diametral Growth and Elongation
Authors: Tipton Steven M.
Published: December 2007

Coiled tubing endures unique cyclic stress and strain histories. The loading imposed on pressurized coiled tubing can trigger deformation mechanisms resulting in incremental plastic diametral growth and elongation. This growth occurs in spite of the fact that both the hoop stress and net axial stress from tension are well below the material yield stress. The most dominant factors controlling the deformation behavior of coiled tubing are the bending-straightening cycles associated with the spool and gooseneck. It is the interaction of the bending stresses and strains with those from axial loading and pressure that result in plastic elongation and diametral growth. Severe cyclic plasticity imposed by these events actually changes the structure of the coiled tubing material, causing a corresponding change in mechanical properties. The material properties in a section of coiled tubing along a string are thus dependent upon the localized service loading history.

The operating parameters that control the loading on a section of coiled tubing are discussed in terms of the tubing geometry, the above-surface deployment equipment and the sub-surface environment. With the load history characterized in terms of imposed stresses and strains, mechanisms that lead to diametral growth and elongation are demonstrated from the standpoint of simple material plasticity models. Refined models are described, based on more sophisticated plasticity relations, capable of characterizing transient behavior and multiaxial effects. Implications from these results for depth calculation are discussed.
Coiled Tubing Management System: A Review After two Years in Operation
Authors: Campbell James Andrew
Published: December 2007

This paper reviews a coiled tubing management system that has been in operation for over two years in European and West African operations. Complete tubing records for up to at any one time 20 coiled tubing units and in excess of 100 strings of coiled tubing have been recorded by the system. Data has been taken from the system, covering the total amount of tubing run over the period and has been broken down to show running footage between different pipe sizes, amount of failures and maintenance carried out on coiled tubing.

Corroboration of the fatigue predictions of the system is also discussed, with test results of tubing that had reached its safe working life under the CYCLE system being tested to destruction on a fatigue rig to evaluate the suitability of the fatigue algorithm used.
Hydraulics Design in Coiled Tubing Drilling
Authors: Walton Ian C. , Gu Hongren
Published: December 2007

Key design considerations in coiled tubing drilling are associated with the wellbore hydraulics, which includes drilling fluid types, liquid and gas injection rates, injection method (gas injection down coiled tubing or through parasite string), circulation, downhole and wellhead pressures, cuttings transport, and rate of penetration. This paper presents a design methodology to achieve efficient hole cleaning and maintain a specified under-(or over-) balance, based on the use of a suite of computer programs. Two design programs are used to determine fluid types and injection rates, and a pump schedule is generated. The pump schedule is then used in a transient computer wellbore simulator to verify that all operational requirements are satisfied for the entire drilling operation. During the design stage, the effects of the coiled tubing size, drilling fluid types, injection method, overbalance or underbalance are investigated using the computer programs. Examples are given to illustrate the design process.
Partnering Lessons from a North Sea Experience
Authors: Stapel Gerard , Wilson Rich
Published: December 2007

Well construction and maintenance partnerships have come of age for the Operator, based on their success in the North Sea environment. This paper examines those critical success factors and provides an overview of how the Operator moved from the back to the front of benchmark performance tables through the application of partnering.

The well construction partnerships typically include the Operators well engineering group, the drilling contractor, the Deviation Drilling and MWD contractor, the well testing contractor, the data acquisition contractor and the cementing contractor.

The Operator currently has three partnerships in place. All of these are driven by a commercial engine that rewards ‘best in class’ performance through an independently benchmarked process as well as providing ‘continuous performance-contingent’ contracts that removes termination clauses and regular tendering and puts the power for contract continuity in the hands of the partnership. This commercial environment has provided an incentive for all the partners to make long term investments in the partnership.

It is considered that true alignment of goals has been achieved with a win/win strategy being applied at the wellsite as well as at managerial and organisational levels. The role of other critical success factors such as; leadership, core strategics and rules, integrated team-working, specialised partnering training, an organisation designed to focus on performance and rewards systems are examined. This paper provides a comprehensive review of the key factors leading to significant performance improvement for the Operator and provides a generic checklist for well construction partnering / alliance efforts elsewhere.
Development of the First Commercial Hot Hole MWD System
Authors: Brady J. K. , Galley T.
Published: December 2007

This paper discusses the development of the industry’s first MWD system designed to operate at temperatures to 175°C (347°F), survive to 200°C (392°F), and withstand circulating pressures of 22,500 PSI. It describes the methodology employed which enabled the product to be taken from a technical feasibility study to a field test in less than seven months. The technical constraints which were overcome to achieve the operating specifications of the system while maintaining high reliability will also be described.
Mechanical Stability Analysis from Drilling Data Alone
Authors: Jones John F. , Barree Robert D.
Published: December 2007

An extremely important and often challenging problem associated with drilling inclined wellbores is maintaining mechanical stability. A number of analytical and numerical models are available in the industry, which aid in evaluating the degree of stability expected in a given wellbore. Application of these models requires input of formation rock properties, which are sometimes difficult and costly, or even impossible to obtain Complicating matters, even with the availability and input of these data, the stability models often inaccurately predict the mud weights necessary to maintain the mechanical stability.1–3

A stability analysis was performed to determine the feasibility of drilling a high angle well (63 degrees) from a Gulf of Mexico platform. Due to the lack of core data, the rock strength properties of the shale sections had to be estimated from prior drilling data.

A case study is presented to compare the estimated required mud weights to the actual mud weights needed to drill the high angle well. The procedures used to determine the pore pressure, fracture gradient, overburden and in-situ stress state are also discussed. Both the commercial and in-house software applications used in this analysis are briefly described and evaluated.

In addition, the potential for developing an empirical model to estimate the rock strength properties of shales is examined.
Applications of Pseudo-3D Stress Analysis Programs for Predicting Borehole Collapse and Formation Breakdown
Authors: Ramos G. G. , Polillo Adolfo , Wilton B.
Published: December 2007

In a drilling/production operating environment, wellbore instabilities arise in all three stages of a well’s life span: drilling, stimulation and production phases. The timing and severity of the occurrence of such borehole problems dictate which method of stability analysis should be used. Pseudo-3D codes are plane-strain, non-isotropic subsets of full 3D numerical and analytical codes. Their speed, portability, and ease of use have popularized them among operations engineers. There are numerous versions of pseudo-3D stress analysis, from simple linear-elastic to sophisticated poroelastic-plastic, each with its own advantage that suits a particular wellbore problem. Simple linear elastic codes are re-emerging in popularity because of ease of use and field-calibration schemes.
Field Cases of Horizontal Well Pressure Transient Analysis in West Africa
Authors: Bourgeois Marcel J. , de la Combe Jean-Luc Boutaud , Deboaisne Renaud M.
Published: December 2007

Horizontal well tests are often difficult to interpret because wellbore storage may partly hide the early-time transient, and an underlying aquifer may alter the late-time data. This paper shows how recent advances in interpretation techniques have enabled us to address these problems.

The first field case shows a well test where both downhole flowrate variations and investigation of the aquifer affected the data. PLT flowrate measurements were used to perform Laplace space deconvolution. In this case, the pressure loss due to friction along the drain behaved like a quadratic skin and could be estimated, and linked to an average friction coefficient.

In the second field case, deconvolution showed that friction could be neglected, as is usually done with infinite conductivity solutions[1].

The third field case gave a questionable match with a conventional horizontal well model, as the lower layer displayed a strong angular unconformity, which precluded final stabilization of the derivative. Thus we used Kuchuk’s multilayer horizontal well solution[2] to model this complex geometry. We had to model the change in rock type and anisotropy in the lower sedimentary unit. It enabled us to get a good pressure match on the derivative of the buildups as well as on the cartesian data plot comprising several transients.
Petrophysical Interpretation of a Multispacing 2-MHz MWD Resistivity Tool in Vertical and Horizontal Wells
Authors: Wu Peter T. , Tabanou Jacques R. , Bonner Stephen D.
Published: December 2007

The multiple phase shift and attenuation resistivities from a 2-MHz array resistivity tool provide the log analyst with the measurements needed to resolve complex interpretation problems associated with high relative dip formations typical in horizontal and highly deviated wells. With the support of modeling, productive zones can be located that may otherwise be missed.

In high relative dip formations, the interpretation of multispacing 2-MHz resistivity tools and the comparison with wireline logs are not straightforward. Therefore, it is imperative for the log analyst to understand the unique response characteristics of these measurements in both vertical and horizontal wells. In high relative dip formations, the primary factors that may cause the resistivity curves of different spacings to separate are borehole effects, invasion, bed boundary proximity and anisotropy. With the help of forward modeling codes and inversion algorithms, the log analyst can resolve most of the interpretation ambiguities.

The responses of a 2-MHz array resistivity tool, with five measurement spacings, to the above factors are illustrated and discussed. Traditional rules of thumb based on vertical well must be modified significantly. Productive zones that would be missed by logs made in a vertical well can easily be detected by logs made in a high-angle or horizontal well through the same formation. A comparison of the resistivity responses of a 2-MHz tool in low and high relative dip formations helps explain the differences between logs made in low-angle and high-angle wells.
Measuring Three-Phase Holdups in Horizontal Wellbores Using Pulsed Neutron Instruments
Authors: Trcka Darryl , van den Berg Frans , Manan W.A. , Peeters Max , Mickael Medhat
Published: December 2007

A new method of determining three phase holdups in horizontal wellbores using pulsed neutron tools has been field tested. A two variable, linear algorithm using the measured inelastic carbon/oxygen and near/far ratios is used to determine holdups. The measurement is fully characterized by Monte Carlo modeling. Laboratory data shows the accuracy of the holdup calculation to be approximately 10%. The method produces a continuous borehole image of the volume fractions of the water, oil, and gas in the borehole. Log examples demonstrate the use of the Pulsed Neutron Holdup Imager in horizontal well production logging and in production logging behind tubing.

Introduction

Three phase hold-up data are essential for remedial action in wells that produce unwanted water and gas. The traditional production logging tool suit consisting of temperature, pressure, fluid capacitance, fluid density, spinner flowmeter and gradiomanometer sensors has proven its utility for production monitoring in vertical wells. In horizontal wells, however, the interpretation of the holdup measurements from conventional production logging instrumentation becomes unreliable due to the fluid segregation. Thus, there is a strong motivation for devising an alternate method of measuring holdups with improved accuracy in horizontal wellbores.

Nuclear measurements offer a method for measuring three phase holdups in horizontal wells with increased accuracy. In contrast to the traditional production logging tools which measure at a localized position in the borehole volume, nuclear measurements average over a larger volume and are relatively insensitive to the segregation and layering of the flow components in horizontal boreholes. Additionally, in single or dual string completions, nuclear measurements can measure nuclear responses through the tubing wall and, therefore, image the annular region of the wellbore that is physically inaccessible to direct measurement. Further, the nuclear measurement offers the possibility of imaging the holdups covering the whole borehole, including by-passed flow around slotted liners and screens.

P. 759
Outsourcing Engineering Services – The Business Side of the Business
Authors: Truman R. B.
Published: December 2007

This paper provides the guidelines for identifying, evaluating, and selecting the appropriate type of outsourcing personnel and estimating the costs associated with using these resources. A description of available personnel resources (consulting companies, service companies, contractors and semi-retired) are provided along with their applicability and usefulness to fulfill outsourcing engineering requirements.

Each of these classes of personnel also command a different price in the marketplace. The means of simply estimating these costs is provided. The rationale for these costs are developed and also presented.

The information presented is useful for all petroleum company managers involved with outsourcing engineering services. This information will provide management with the guidelines for selecting a service provider which will fit their needs. The methods presented for estimating costs will assist planning and budgeting of outsourcing expenses.

As oil and gas companies downsize many personnel have become consultants or contract service providers to the petroleum companies. This paper will provide these people with guidelines for positioning themselves in the market. In addition, it also provides a method of determining their true costs.

This paper will not discuss the correct pay for full time employees. It will discuss what a petroleum company should expect to pay and what the service provider should expect to receive based upon the base salary of a full-time employee for the equivalent job within a petroleum company.
Recent Trends in Hydraulic Fracturing
Authors: Wieland D.R.
Published: December 2007

Trends in hydraulic fracturing over the years have closely followed an increased knowledge or better understanding of what occurs in the formation during a fracturing treatment. As more and more knowledge was gained emphasis shifted from materials to horsepower and high injection rates. Recently the shift has been back to materials and more careful planning and engineering of individual treatments.

Improved technology within the past two or three years has led to the development of new, viscous fracturing fluids and more sophisticated computer programs. These developments have greatly improved results of fracturing treatments and have made it possible to successfully stimulate those wells which previously were poor candidates for hydraulic fracturing poor candidates for hydraulic fracturing treatments.

The purpose of this paper is to discuss recent developments in fracture fluids and techniques and the technology involved in their use. Case histories are used to show the improvements in economy, efficiency, and increased production results.

Introduction

Since the introduction Hydraulic fracturing as a stimulation tool in the late 1940's, development trends have closely paralleled each fact learned concerning what actually takes place in a formation during a fracture treatment place in a formation during a fracture treatment In the early days, equipment available was capable of providing injection rates of one to two barrels per minute and screen-outs were common. It was felt that viscous fluids would suspend and transport propping agents better and development emphasis was on fracture fluids. Heavy refined oils became common frac fluids and water-in-oil emulsions, acid-in-oil emulsions, and soap-type oil gels appeared.

Next, fluid loss was recognized and fluid loss agents were introduced. It was discovered that in many cases crude oil could be used as a fracture fluid with these new agents and treating economics apparently improved. The trend to crude oil with fluid loss agents, however, increased the incidence of screen-outs until a relationship between injection rates and screenouts was found. Increased injection rates reduced the probability of a screen-out and equipment was built to provide higher rates.
Reservoir and Production Characteristics of the Clinton Sand, East Canton Oilfield
Authors: Watts Royal J. , Schrider Leo A. , Craig Jerry G.
Published: December 2007

Geophysical well logs, petrographic thin section core analyses, and production- and pressure-decline curve analyses were used to pressure-decline curve analyses were used to characterize the geology and to estimate the reserves, recovery, and well life of the East Canton oilfield, northeastern Ohio. Clean sand sections of the Clinton were found to contain an average of 95 percent quartz and less than 4 percent clay. These sections correlated with the 80-percent-sand line determined by gamma ray logs and with core permeabilities averaging more than 0.1 permeabilities averaging more than 0.1 millidarcy. Production was found to be more closely related to thickness of 80 percent sand than any other reservoir characteristic. Economic life and output of the wells studied are predicted to be approximately 10 years and about 30,000 to 40,000 barrels per well. A primary recovery factor of 9 to 12 percent is indicated. Primary reserves of the 60,000-acre field are a minimum of 51 million barrels. Approximately 500 additional wells will have to be drilled to complete development of the field. With such a low primary oil-recovery factor, much oil will remain for secondary recovery possibilities.

Introduction

The East Canton oilfield is one of the largest in the Appalachian Basin (Fig. 1) and contains important primary and secondary oil reserves. The reservoir has low porosity and permeability, and hydraulic fracturing is permeability, and hydraulic fracturing is needed to stimulate wells to economic production. More than 60,000 acres of proved production. More than 60,000 acres of proved production are available with more than 1,000 production are available with more than 1,000 wells, and there are infill locations for at least 500 more. Over 14 million barrels of oil have been extracted from the field, and current production is 10,000 to 11,000 barrels per day. The Bureau of Mines undertook these per day. The Bureau of Mines undertook these studies to obtain information for possible secondary recovery considerations in this field.

Reservoir and production characteristics of this field have never been clearly understood, however, and such information is essential to productivity predictions and maximum recovery. productivity predictions and maximum recovery. Geological and reservoir studies were made in an effort to obtain this information. Techniques and methods utilized included pressure buildup tests, PVT bottom-hole sample test, production decline and pressure decline production decline and pressure decline analyses, and correlation of geophysical well log data with oil production data from over 100 wells.