bluuebunny/crossref_metadata_2025 huggingface dataset:
A Complete Hydraulics Model for Horizontal Wells
Authors: Siu Alan , Shin Dalsoo , Subramanian Ganesan
Published: December 2007

A horizontal well usually yields a high rate through its long perforation interval, resulting in a large frictional pressure drop that is believed to reduce the well productivity.

Unlike conventional horizontal well methods which consider the horizontal section only, the proposed model also includes the vertical section of the well and the surface facility from the well head to the GOSP. The hydraulics model was validated stage-by-stage by various known solutions, and then applied to a high rate well.

It was found that the effect of frictional pressure drop on oil rate was not as pronounced as suggested by analytical methods, or some numerical simulation studies. In summary, the pressure drop in the vertical section of the horizontal well plays an especially important role in deciding how much fluid can be produced. Therefore, it is recommended to be an integral part of horizontal well models.
Shocks in Solution Gas-Drive Reservoirs
Authors: Herrera Ismael , Chargoy Lucia
Published: December 2007

abstract

Black-oil models neglect diffusive mechanisms such as molecular diffusion or mechanical dispersion; this omission produces a propensity to developing shocks. This paper aims to carry out an exhaustive identification of the kind of shocks that can occur when black-oil models are applied to problems in which the bubble-point varies and to establish the conditions under which they are generated. In addition to shocks of Buckley-Leverett type, two other classes of shocks and a bifurcation mechanism, are identified. Except for shocks of Buckley-Leverett type, all other shocks may occur in the presence of capillary forces. The paper contributes to clarify several aspects of black-oil models and to understand pathologies that occur in their numerical implementation.
Dynamic Pseudos: How Accurate Outside Their Parent Case?
Authors: Ekrann Steinar , Mykkeltveit Johannes
Published: December 2007

If properly constructed, dynamic pseudos allow the parent solution from which they were derived to be exactly reproduced, in a certain well-defined sense, in a subsequent coarse grid simulation. The paper reports extensive numerical experimentation, in 1D homogeneous and heterogeneous media, to determine the performance of pseudos when used outside their parent case. We perturb fluid viscosities and injection rate, as well as realization. Parent solutions are produced analytically, via a generalization of the Buckley-Leverett technique, as are true solutions in off-parent cases. Capillarity is neglected in these experiments, while gravity is sometimes retained in order to force rate sensitivity.
Theoretical Investigation of Countercurrent Imbibition in Fractured Reservoir Matrix Blocks
Authors: Chen J. , Miller M. A. , Sepehrnoori K.
Published: December 2007

Countercurrent imbibition is an important oil recovery mechanism in fractured reservoirs. The imbibition process can be described by a nonlinear diffusion equation that has self-similar solutions. In this paper, we use the diffusion equation to conduct numerical experiments of countercurrent imbibition in a single matrix block to identify flow characteristics. The result demonstrates that the widely-used Aronofsky et al.1 exponential relationship is only valid for cases where diffusion coefficients are constant. The nonlinear diffusion equations in one and two-dimensions are analytically solved using a relative flow rate concept to simplify the analysis. The result is a new understanding regarding the effects of various parameters such as capillary pressure, relative permeability, mobility ratio, and fractional flow on countercurrent imbibition.

The solutions can be directly used to modify an existing single porosity model to a dual porosity model for simulating fractured reservoirs. Results show that our approach provides fairly good accuracy compared to a full-scale dual porosity model with little increase in computation time over single porosity modeling.
Characterization of Trapped Gas Saturation and Heterogeneity in Core Samples Using Miscible-Displacement Experiments
Authors: Smith D. H. , Jikich S. A.
Published: December 2007

Trapped gas saturation and permeability heterogeneity were evaluated in Berea cores at reservoir conditions, using standard miscible displacement experiments, with and without surfactants. Pressure and production history were influenced by core heterogeneity and foam lamellae formation when aqueous surfactant was present in the core.

A simple dispersion model and a three-coefficient dispersion-capacitance model (Coates-Smith) were fit to the experimental data. The dispersion-capacitance model successfully matched the experiments in which foam lamella formed, while the simple dispersion model was used only for determining initial core flow heterogeneity.

The objective of the dispersion-capacitance model was to estimate trapped gas saturations; however longitudinal dispersion and mass transfer also were examined. The results show that the dispersion-capacitance model accurately fits trapped gas saturation controlled by rock heterogeneities and foam lamellae for lamella generating mechanisms that allow a continuous gas phase (leave-behind lamellae). The practical applications resulting from this study can aid in core sample selection and scaling short laboratory corefloods to field dimensions for applications to foam stimulation and underground storage of natural gas.
Laboratory Investigation of Parameters Affecting CO2-Foam Mobility in Sandstone at Reservoir Conditions
Authors: Yaghoobi Hossein , Heller J. P.
Published: December 2007

In CO2 floods the large viscosity contrast between the reservoir and injected fluids induces an unfavorable mobility ratio that results in early breakthrough and consequently decreases oil sweep efficiency. There is evidence that the presence of an aqueous surfactant solution will produce a foam with CO2. This not only controls the gas mobility but may also selectively reduce the gas mobility through regions of differing permeabilities. This could be a very favorable phenomenon in EOR processes if it occurs in the reservoir. The purpose of this study is to evaluate foam application from these perspectives.

This study concerns a series of steady-state CO2-foam flow experiments in Berea sandstone cores at typical reservoir conditions. The effects on foam mobility of flow rate, foam quality, surfactant type, surfactant concentration, and rock permeability were investigated. Four commercial surfactants (Chevron Chaser™ CD 1040, CD 1045, CD 1050 and Shell Enordet 2001) at 500 ppm and 2500 ppm concentrations (in 2 wt% brine) were used. In each run the contribution of each parameter on foam mobility was evaluated independently.

Our results have shown that the mobility of 80% quality foam increased with increasing total flow rate for all four surfactants. As evidenced by increased pressure drop, foam was generated in all runs, including those in which the total Darcy flow velocity was as low as 0.04 fit/d. Selective mobility reduction, in which the measured mobility was reduced further in high permeability cores, was observed for some but not all surfactants at certain flow rates. Some sequences of experiments were performed in which the flow rate of one phase was held constant, while that of the second was increased from one run to the next. Between experiments, in each sequence, it was observed that pressure drop depended little on gas velocity. Our results also showed that foam mobility increased with increasing liquid velocity in all the runs. We also found that the foam mobility increased slightly as foam quality increased up to about 85 % and then rose quite rapidly as foam became dryer, up to about 98 % CO2. Foam hysteresis was also investigated in 36 experimental runs and was found to be absent in almost all cases within a reasonable experimental error.
Screening Restimulation Candidates in the Antrim Shale
Authors: Hopkins C. W. , Frantz J. H. , Tatum C. L. , Hill D. G.
Published: December 2007

This paper describes a simple method to identify, prioritize, and evaluate restimulation candidates in the Antrim Shale of the Michigan Basin. This work is being performed as part of an ongoing field-based Gas Research Institute (GRI) project investigating the Antrim Shale. There are between 500 and 1,000 Antrim Shale wells which could be candidates for restimulation due to previous screenouts and/or flowback problems, when sand consolidation material was not used. However, all of these wells might not benefit from restimulation, due to either poor reservoir quality or because the wells are already effectively stimulated. Based on historical results, we estimate the increase in reserves from restimulation could be between 50 and 400 MMscf per well, which could add 50 to 200 Bscf in future reserves from the 500-1,000 candidate wells.

We have developed a novel injection test unit and procedure to help operators identify the best restimulation candidates in a cost-effective manner and in a reasonable amount of time. The test is designed to determine if there is an effective hydraulic fracture connected to the wellbore. To our knowledge, a test of this nature has not been used before for specifically identifying restimulation candidates. To date, we have run 50 tests, and identified potential restimulation candidates from about 1/3 of the tests.
The Use of Production Logs to Evaluate Completion and Stimulation Effectiveness
Authors: Harris Perry , Holsclaw Steve , Mullen Mike , Sagan Mike , Frisch Gary
Published: December 2007

The current economic structure of the petroleum industry often requires multiple completions with production from each zone commingled to reduce completion costs. However, these multiple completions require a different approach for analyzing the effectiveness of both the original completion and possible later stimulation treatments: rather than costly individual zone testing, production logs can be run to detect the contribution of each zone to the total production rate.

When multiple pay zones are treated and evaluated together, the reservoir engineer faces the problem of determining whether or not each zone benefited from the chosen treatment. In the case of multiple completions, well testing using either drawdown and/or buildup is expensive and complicated. Production logs make it possible to determine the type and rate of the produced fluids from each individual zone in a timely manner. By comparing the logging tool responses taken before and after stimulation, the effectiveness of stimulation can be determined. This will identify zones requiring further treatment and help determine the optimal type of treatment. In addition, valuable information for future wells can be gathered efficiently in terms of both time and money.

Guidelines for running production logs are presented and the usefulness of production logs for evaluating multizone completions is demonstrated. Several examples highlight how production logs can be used to analyze multizone completions in tight gas areas.
The Application of Kohonen Type Self Organization Algorithm to Formation Evaluation
Authors: Chawathé Adwait
Published: December 2007

Reliable and comprehensive well log data is essential for a reasonable evaluation of the underground rock formations and the in-situ hydrocarbons. This log data has to be interpreted with good statistical confidence to predict the performance of a well. In order to automate the process of log interpretation and hence potentially reduce its cost, a Neural Network (NN) can be trained for interpreting logs with reasonable accuracy. This paper discusses the possibility of applying the Simulated Neural Network (SNN) technology to the art and science of well log interpretation.

The algorithm used to generate the SNN used the Kohonen unsupervised learning technique. Basic principles of the SNN thus created have been considered and the results obtained from the training and SNN log interpretation have been discussed.
Technology Transfer Around the Corner?
Authors: Willis R. B. , Rowell Deborah , Patchen Douglas
Published: December 2007

This paper will describe how the Oil and Gas industry can become involved in shaping a new national program to aid in the transfer of technology from a variety of sources to the hands of the local independents.

Technology Transfer has been a "buzzword" in the Oil & Gas Industry for some time now. Most of us might admit that it has been more of a "buzzword" and less of an activity than we would like. While most of the operators in the Appalachian Basin want to apply the latest in technology to their exploration and production activities is has quite often been difficult to find the appropriate technology. The Department of Energy, realizing that much of the technology which exists involving Oil and Gas is seldom applied by those who work so hard to produce it efficiently, has instigated the Petroleum Technology Transfer Council (PTTC). The PTTC will be a national "umbrella" organization formed by the Independent Petroleum Association of America (IPAA), in cooperation with the state and regional oil and gas producer associations, the Gas Research Institute (GRI), the Interstate Oil and Gas Compact Commission (IOGGCC), and other groups. The mission of the PTTC is to foster the effective transfer of exploration and production technology to domestic producers in all regions of the country. One of the most important functions of the program will be to provide a feedback loop so that the needs and concerns of producers can be communicated effectively to the entire research community and to the Department of Energy.

The PTTC program has three main components: Problem Identification WorkshopsFocused Technology WorkshopsRegional Resource Centers

The PTTC has the potential to aid producers in the Appalachian Basin if they understand the program and become involved in directing it to serve their needs. 1994 will be the formative year, ultimately deciding its acceptance by regional producers.
Cost and Resolution in 3D Surveys for Stratigraphic Traps
Authors: McDonald J. A. , Tyler N. , Uren N. F.
Published: December 2007

The three-dimensional seismic method is now widely recognized as a very valuable tool for characterizing reservoirs. We show that an understanding of the tool's resolution capabilities can be readily made in the laboratory using models. Channelized reservoir systems such as fluvial deposits can be characterized by the careful use of the three-dimensional methods, VSP and bottom-hole pressures and an example is given from a mature field in Texas.
Applications of Risk Analysis in Petroleum Exploration and Production Operations
Authors: Moore Kevin S. , Cockcroft Peter J. , Prasser Ross
Published: December 2007

Risk analysis is a method of quantifying the effects of uncertainty on decision outcomes. In many E&P decision analyses, evaluators do not explicitly consider the uncertainties and possible decision outcomes but instead present only a single, most likely result. Often the uncertainties are considered subliminally. This practice can lead to sub-optimal decisions.

Explicit forms of risk analysis can improve decisions by providing more accurate representations of possible outcomes. This paper will illustrate decision and risk analysis techniques applied to several technical decisions in E&P operations. Although uncertainties exist in many different areas – technical, environmental, political, corporate, – only those in technical project evaluations will be discussed.
Application of Resistivity Inversion Software to Thin-Bed Evaluation
Authors: Warrilow I. M. , Ibrahim Rusidah , Chin Ho Tiong , Forsyth D.
Published: December 2007

In a seemingly ever growing number of fields, the petrophysicist is being confronted by the challenge of evaluating thinly bedded formation sequences (i.e. beds whose thickness is below the resolution of most of the contractor "standard" open hole logging tools). The evaluation of such beds is indeed a challenge as more often than not the available wireline data does not provide anywhere near sufficient resolution to enable a proper evaluation of such beds. At best, the interval may be cored and indications of hydrocarbons detected. At worst, the interval could be totally over-looked due to misinterpretation and business opportunities missed.

To assist the interpretation of such zones the mathematical technique of "inversion" has been applied to the resistivity suite of logs. Through the use of "inversion" or "resolution enhancement" software the apparent resistivities (derived directly from the resistivity tool) are automatically corrected for such environmental effects as shoulder-bed (bed boundary) effect, saline-borehole fluids and invasion. This results in "true" formation resistivity values being obtained on a layer by layer basis. The technique is not restricted to the more recent logging tools but is also applicable to the older resistivity tools (normal and lateral devices).

This paper will demonstrate, through a number of field examples, how the inversion technique can be applied to substantially improve our current understanding of "true" formation resistivity and thus our "conventional" petrophysical evaluation.
Effects of Polymer Concentrations, Slug Size And Permeability Stratification in Viscous Waterfloods
Authors: Wang G.C. , Caudle B.H.
Published: December 2007

A streamline type mathematical model has been developed which may be used to study oil recovery by viscous waterfloods for any desired well spacing. The model was used to study the combined effects of permeability stratification, polymer concentration and viscous water slug size for a five spot injection pattern.

Five different permeability profiles ranging from a homogeneous to a highly stratified reservoir were studied. It was found that viscous water floods show greater percentage increase (over conventional water percentage increase (over conventional water floods) in oil recovery for stratified reservoirs than for homogeneous reservoirs. A highly stratified reservoir containing viscous oil showed a 96% increase in recovery for a particular viscous water flood. it was also found that the adverse effect o connate water on oil recovery becomes insignificant as the degree of permeability stratification approaches a large number.

Guide-lines for the determination of an optimum slug size and viscosity were derived. Generally speaking, it is advisable to use a high viscosity, small size slug in flooding a homogeneous formation, while stratified reservoirs do better with the use of a large diluted slug. It was found that there exists an optimum slug size for a given amount of thickening chemical depending upon the oil viscosity and degree of permeability stratification. The increase in oil recovery by selecting an optimum slug size may be sizeable in some instances.

Introduction

The role of mobility ratio in water flooding has been well established. Thickening of the injected water or otherwise increasing its resistance to flow brings about this improvement through a decrease in its fluid mobility. Early attempts to decrease the mobility of the injected water were uneconomic, but, during the past few years, the use of a high molecular weight water-soluable polymer has shown promise as an effective polymer has shown promise as an effective material in reducing the water mobility. Results from both laboratory and field pilot tests indicate that the concentrations of polymer required in the injection water to polymer required in the injection water to effect substantial increase in flooding efficiency are usually low enough to satisfy normal profitability criteria.

Much has been written postulating the mechanisms by which the mobility of water is reduced by the addition of a polymer.
Optimized Exploration Resource Evaluation Using the MDT Tool
Authors: Zainun K. , Trice M. L.
Published: December 2007

This paper discusses exploration cost reduction and improved resource delineation benefits that were realized by use of the MDT* (Modular Formation Dynamic Tester) tool to evaluate exploration prospects in the Malay Basin of the South China Sea. Frequently, open hole logs do not clearly define fluid content due to low salinity of the connate water and the effect of shale laminae or bioturbation in the silty, shaly sandstones. Therefore, extensive pressure measurements and fluid sampling are required to define fluid type and contacts. This paper briefly describes the features of the MDT* tool which were utilized to reduce rig time usage while providing more representative fluid samples and illustrates usage of these features with field examples. The tool has been used on several exploration wells and a comparison of MDT* pressures and samples to results obtained with earlier vintage tools and production tests is also discussed.
Determination of Petrophysical Parameters Using Wireline Logs in Low Salinity Reservoirs
Authors: Goode Peter A. , Pietsch Andrew P. , Williams Neil V. , Sibbit Alan M.
Published: December 2007

This study defines an approach to determine porosity, fluid saturations and permeabilities from wireline log data in sandstone reservoirs containing low salinity formation brines. An extensive set of measurements were made on low invasion core were analyzed to establish the ground truth, and to control the input parameter choices for log analysis.

A recently developed water saturation equation, that accounts for the different geometry of the conducting paths along grain surfaces and within the pore fluid, was used to analyze the wireline resistivity logs. This equation predicts far less resistivity contrast between hydrocarbon and water-bearing intervals than other widely used relationships.

The log interpretation technique consists of making robust estimates of highly sensitive parameters such as the cation exchange molarity, Qv, and paying attention to the details in the estimation of the true formation resistivity, Rt and the formation resistivity factor, F.
Application of Reservoir Management and Reservoir Simulation to Monitor and Improve the Performance of the M4/7/N1 Reservoirs in the Samarang Field, Offshore Sabah, East Malaysia
Authors: Baxendale David
Published: December 2007

The Samarang field was discovered in 1972, offshore south west Sabah, East Malaysia. The field was declared commercial in 1974, and first production commenced in 1975. The M4/7/N1 cluster of reservoirs is one of the main groups of reservoirs in the Samarang field, containing some 23% of the field's expected ultimate recovery. The observed basal/edge natural water drive and the gascap expansion drive are expected to recover about 50% of the M4/7/N1's original oil in-place. However, the combined drive was not anticipated to fully sweep the reservoir. Hence, the need for a field wide review of the reservoir.

To actively manage the remaining hydrocarbon resource a detailed 3D full field simulation project was initiated. A comprehensive geological study of the M4/7/N1 reservoirs was first conducted to formulate the geological input to the simulation model. The model was validated by history matching the reservoir's seventeen years of production data, This model was then used to actively manage the hydrocarbon resource base by: predicting future oil recovery under various development options, locating potential infill well locations, and by optimising the reservoir management strategy.

Reservoir management of this mature field through the utilisation of reservoir simulation tools, has helped to maximise hydrocarbon recovery by determining the optimum depletion strategy with respect to the remaining hydrocarbon resource. Future infill drilling locations have been identified and the results from the model have been used to support the operator's development strategy for the pool.
Review Of Early Horizontal Well Applications In Central Sumatra
Authors: Arnold C.W. , Djauhari H.H.
Published: December 2007

C.W. Arnold* and H. H. Djauhari*

This paper reviews the first applications of horizontal wells in the Caltex Pacific Indonesia (CPI) area of operation in Central Sumatra, Indonesia. Drilled in late 1993 and early 1994, these wells now provide enough history for an initial evaluation of the results. These results are encouraging and CPI is reviewing further applications of this technology, which is viewed as another technique for squeezing more oil out of mature fields. The project histories, ranging from concept to evaluation, drilling, and actual performance results, are briefly covered. Emphasis is placed on the evaluation methodology, involving a blend of analytical and simulation methods, and comparison of performance predictions with actual results.

Introduction

CPI's area of operation is characterized by numerous mature fields with significant reserves, permeability, aquifer influx, and multiple stacked sandstone reservoirs. High producing water cuts and water coning are significant problems. Both the Minas and Petani fields used horizontal wells to target thick bottomwater sands which cone significantly in vertical wells. In Minas, the objective was to reduce water cut and capture bypassed oil from a fining upward section. In Petani, the concept was to reduce coning, increase rates, and improve well management by allowing the recompletion of existing vertical wells upward into unopened pay.

The evaluations included a review of the geology and performance predictions designed to address the complications in each field. These include the very high permeabilities and fining upward sequence in Minas and the influence of neighboring wells in Petani. Generally, the results have been good and these projects offer useful case histories of horizontal well applications.

Background

Both the Minas and Petani fields are located in the Pertamina-CPI Production Sharing Contract Area in Central Sumatra, Indonesia (Fig. 1). The Minas field is the largest in Southeast Asia with an estimated original-oil-in-place (OOIP) of nine billion barrels. The Petani field, although smaller, is still sizeable with an estimated OOIP of about 690 million barrels. Petani is located 12 miles west of the Duri field, site of a large steamflood operation. Significant oil reserves remain in both fields and methods of efficiently recovering that oil are of strategic interest to the company.

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Centrifugal Wellstream Separation of Water and Sand
Authors: Christiansen Bjørn , Kvamsdal Dag , Dannström Henrik
Published: December 2007

This paper discusses problems and technical solutions in developing a non-rotating centrifugal separation system to remove water and sand from the well fluid prior to choking and multiphase transport from a satellite field.

The paper focuses on the usefulness of CFD-tools for hydraulic design of the primary oil/water separator. Furthermore, the experimental investigation of the gas/liquid separator and the primary oil/water separator are described in terms of scope, test rig setup and preliminary results. Finally, other applications utilising parts of the project core technology, are briefly outlined.
Incorporation of Production Data in a Reservoir Description Process
Authors: Oetomo Hari K. , Kelkar Mohan G.
Published: December 2007

In this study, we propose a technique to include production data as a part of the constraint in a reservoir description process. Based on the simulation studies, we observed that, during secondary recovery performance, the production parameters such as water breakthrough are closely tied to the connectivity between injectors and producers. Using this relationship, we introduce a method which allows incorporation of production data as a part of the constraint through an equivalent static parameter. For the purpose of incorporating this information, we use the method of simulated annealing.

Using this connectivity function along with the near-well permeability, we show that the uncertainty in the reservoir description is significantly reduced. We validate our results by conducting the reservoir simulation for a full field scale simulation based on the Burbank Field in Oklahoma. These results clearly indicate the need for the incorporation of production data in generating the reservoir description.
Gas Fields Development in Malaysia
Authors: Seong Chen Kah , Husain Darwis , Karim Abdul Hamid Abdul
Published: December 2007

This paper is a review of the gas fields development in Malaysia. The major subsurface engineering considerations for gas development include drive mechanism determination, well requirement, completion strategies, well deliverabilities, recovery factor and reservoir surveillance requirements. For surface engineering, the major considerations include offshore facilities function, platform configuration and sequence and process and compression requirements. The result of the review is the summary of some of the differences in gas fields development to date.
Concrete Platforms for Southeast Asia
Authors: Hoff G. C. , Reusswig G. H.
Published: December 2007

The use of concrete offshore structures for hydrocarbon resource developments in SE Asia has, to-date, had little precedent but their potential across the region seems unlimited. The interest is continuing to grow because the structures can be built using local materials and local labor in the countries where the platforms are to be used. For many applications, they are cost competitive with steel structures. The concrete substructure requires little or no maintenance throughout the life of the structure, thus reducing operating costs. The concrete structures can be self-installing without the use of crane barges or heavy-lift vessels. They are re-floatable and can be used again in other locations. They also can be designed to include oil or condensate storage within the structure, thus eliminating the need for additional floating storage in areas where offshore pipelines do not exist. The paper describes a few concrete structure concepts that are applicable for Indonesia, Malaysia, Vietnam and Australia and considerations for their use.
Development and Verification of Flexible Pipes for Deepwater Applications
Authors: Makino Yoshiyuki , Kagoura Toru , Ishii Kenichi , Fuku Tadashi , Kawakama E. H. , Yamaguchi Takumi
Published: December 2007

In 1993, Furukawa Electric delivered flexible pipes to PETROBRAS for use in deep offshore oil field at 500 m of water depth. This paper presents flexible pipe design points, development item, type approval and verification for deepwater applications.
IADC's Well Control Accreditation Program (Well Cap)
Authors: Kropla S. M.
Published: December 2007

In early 1995, the International Association of Drilling Contractors will implement its Well Control Accreditation Program, known as WellCAP, throughout most parts of the world. WellCAP marks the first attempt by the drilling industry to put in place a comprehensive system to define a core well control training curriculum, establish minimum standards and recommended guidelines for course structure, and provide a means of formally recognizing schools which meet the association's accreditation criteria. Originally intended primarily for use in emerging and undeveloped areas, the program has since been proposed as an alternate method of approving well control schools in the U.S.
Analysis of Drillstring Failures
Authors: Reid David , Rabia Hussain
Published: December 2007

The drilling industry is currently exploring various ways of reducing drilling costs through a multitude of initiatives; for example C.R.I.N.E. (Cost Reduction In the New Era). One of the major areas where there is potential for cost reduction is downtime due to hole problems and drillstring failures.

Over the last five; years, British Gas (B.G.) has experienced a number of drillstring failures despite following the industry accepted practices of drillstring design. As a result of this, a substantial research programme was initiated to investigate the fundamental mechanics of drilling vibrations, and in particular the prediction of the onset of a resonance that contributes to a fatigue failure. The programme concentrated on four major areas: A full metallurgical analysis of the failed components;Development of mathematical models to predict natural frequencies;A collection of field data; andBuilding a laboratory based scale model drillstring rig to generate vibration data and validate the mathematical models in conjunction with field data.

This paper presents details of the above research programme that results in a substantial reduction of drillstring failures. It will present field examples from both onshore and offshore wells. The paper also details British Gas's approach to the reduction of harmful resonance through the strategic placement of a shock sub.
Makeup Torque and Rotary Shouldered Connection Reliability
Authors: Baryshnikov Anatoly , Ferrara Paolo , Schenato Adelmo , Curioni Emilio
Published: December 2007

This paper presents an analysis of the makeup torque influence on Rotary Shouldered Connection (RSC) reliability under static and dynamic loads. Both theoretical and experimental results of torque-turn diagrams and full scale fatigue tests are shown. The paper gives recommendations for the optimum makeup torque under cyclic loads for different material characteristics and suggests an operative patented method to estimate optimum makeup torques for connections directly at the rig site. Results are presented and discussed for different tool joint and drill collar connections. All conclusions are illustrated with a set of plots describing the results of the investigations.

Introduction

RSC friction capacity. A good make up quality is achieved by creating optimum preload conditions (axial loads) into connection by means of a makeup torque. This make up will guarantee maximum RSC reliability under applied static and/or dynamic loads and mud pressure. The main RSC geometrical parameters and friction coefficient on contact surfaces define the RSC friction capacity and preload condition into connection under the application of a given makeup torque. In the early days of deep drilling very little was known about RSC friction coefficient during making up and the friction coefficient was usually taken to be equal to 0.2. In 1950-60 a set of RSC makeup tests was developed with different compounds. Special connection design threads were used. Connections were made up at a given makeup torques and makeup axial loads were estimated by pin elongation measurements. These investigations showed that RCS friction coefficient without dope was equal to 0.133, while with the common dope used at the rig site (60% lead powders 40% grease base) it was equal to 0.08. This friction coefficient was accepted by API as a standard value for drilling calculations though it is not the same for different kinds of compounds, RSCs and drilling conditions.

The results of both theoretical and experimental investigations show that RSC optimum makeup torques are different under static and dynamic (fatigue) loading conditions and can be estimated. However, it is difficult to use existing recommendations at the rig site due to the influence of different technical and technological factors (well conditions, geometrical and mechanical connection parameters, frictional properties of thread compounds and so on) on the optimum makeup values. RSC friction capacity depends on different factors and may vary within a large range (more than 50%) during connection life and from one assembly to the other. While drilling, an improper break-in procedure, cleaning and lubrication of RSC may lead to local thread (or shoulder face) galling and dramatic changing of its friction capacity.

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A Model for Shock Sub Performance Qualification
Authors: Parfitt S. H. L. , Abbassian Fereidown
Published: December 2007

This paper investigates the influence of the interaction between a tricone bit and the drilled formation on the axial dynamic behaviour of the drill string, with the aim of qualifying shock sub performance. It presents a simple tricone bit model including both material removal and the non linearity of lift off, which makes no assumptions as to the form of the bottom hole pattern. The model generates a trilobe pattern and the associated phenomena typically found in field data from tricone bit drilling in hard formations: power spectral density peaks on the low frequency side of 3xRPM and 6xRPM etc during 'smooth' drilling, and the beating phenomenon.
Slim Hole Drilling Package Proves Cost Effective in Remote Location
Authors: McNicoll R. M. , Schneider Georg , Marquardt P. , Martin David , Skekel D.
Published: December 2007

The Manandaza South-1 slimhole exploration well was drilled in Madagascar during the period August to October, 1993. From receipt of tender documents to spud took 24 weeks. The well was drilled and satisfactorily evaluated, terminating in a 41/8" hole, at 60% of the cost of the nearby offset. It was drilled on a partnership basis using a small, modified workover hoist. The success of this venture has led the operator to plan future wells along similar lines.
Marginal Fields Development Using an Innovative Drilling Rig
Authors: Grandi Maurizio , Calderoni Angelo , Schenato Adelmo , Cicognani Claudio
Published: December 2007

The Oil Industry is actively involved in screening new technologies to solve a common problem: to reduce capital expenditures as well as to minimise environmental impact.

Budget reduction has forced several Oil Companies to identify new solutions: for example, in onshore applications, slim hole drilling has been recently seen as a suitable tool for cost reduction in a variety of applications such as frontier basins and prospect evaluation, re-entries, production from marginal fields and so on.

An overview is presented on low cost drilling for marginal fields production in mature areas.

In relation to this particular scenario, appropriate technologies have been investigated with the above aim.

An innovative drilling rig, particularly tailored for marginal fields development, is presented in the paper along with the preliminary results of field applications.
New Remote Control-Conventional Drawworks
Authors: Dupuis Dominique , Girault Alain , Codron Michel
Published: December 2007

Most drilling rigs are equipped with a drawworks (DW) powered by one or several electrical DC motors. The DW has a braking device consisting of a mechanical brake and an eddy current brake (ECB). Standard controls are direct and multiple; as a result, the work station of the driller is located and engineered around these controls. This is anything but friendly to actuate with a lack of good ergonomic design.

This paper will describe how, without modifying any of the mechanical components and associated equipment of a conventional existing DW, a remote single joy stick allows the control of the upwards and downwards loads speed and automatically operaties the different components.

The engineering of the system relies on the electrotechnical controls of the power components concerned (DC motors and ECB) associated with adequately controlled and placed sensors. It shall be noted that the mechanical brake will be only used for emergency and "parking".

The paper will outline the field results and analyse the benefits of a such new control in term of ergonomy and location of drillers cabin. A consequence of this system is a refined control of the weight on hook. It is obvious that this system implements all the principle components for an automatic positionning of the travelling block.
ERC Conversion
Authors: Adkins D. W. , Laird J. S.
Published: December 2007

The Extended Reach Cantilever (ERC) is a jack-up conversion designed to maximize the capabilities of an existing slot-type unit by converting it to an enhanced cantilever drilling unit. Enhancements were designed to optimize capabilities and minimize weight and cost.
Why Use a Top Drive on a Land Rig, or When?
Authors: Tyson R. W. , Schuck J. D.
Published: December 2007

The ultimate drilling customer is the Operator and his economics dictate when and how often he drills. Reducing overall well cost allows the operator to increase his drilling program. Can top drive drilling systems pay off for the operator and land contractor?

The purpose of this paper is to provide a comparison of drilling with and without a top drive on horizontal land wells. Actual drilling data and economics will be compared and analyzed. Advantages, limitations, and operational costs will be reviewed. The integration of the top drive system into a land rig, portability, installation, and operation will be examined.

The needs of the operator were conveyed to a specific drilling contractor who in turn developed a portable drilling package with a manufacturer, which would meet all the operational requirements and economics. The result stretches the operator's drilling dollar, and the contractor's rig utilization.
Use of a Novel Drill-In/Completion Fluid Based on Potassium Formate Brine on the First Open Hole Completion in the Gullfaks Field
Authors: Svendsen Øjvind , Toften J. K. , Marshall D. S. , Hermansson C. L.
Published: December 2007

This paper describes the first use of a novel drilling fluid based on potassium formate brine and weighted with manganese tetraoxide. Also included is the completion technique used to open hole complete an unconsolidated reservoir. The fluid was selected for maximum brine density, and to facilitate removal of the filtercake. Criteria for fluid and completion selection are presented together with laboratory work conducted to optimise the fluid and the completion for a specific application.

Potential problems related to operations and working environment were identified through a risk analysis approach. Predicted solutions are compared to actual field experience. Key factors included minimisation of ECD, monitoring of soluble barium in the drilling fluid, rig-crews' exposure to manganese tetraoxide and barium, and procedures to combat lost circulation. The filtercake removal and its transportation through the pre-packed screen completion were comprehensively investigated.

The perceived benefit of the formate brine system was the possibility to drill, complete and produce an unconsolidated, pressure sensitive reservoir with the same fluid.

This was achieved with minimal on-site fluid treatment. The fluid was significantly more expensive than conventional alternatives. However, based on drilling fluid performance, rig-time and well productivity, one can conclude that the field test was successful and the use of the fluid was justified.
Improved Fracturing Technologies Provide for Increased Well Productivity: A Case Study on Red Fork Formation Wells
Authors: Tjon-Joe-Pin Robert M. , Brannon Harold D. , Handren Patrick J.
Published: December 2007

A case study has been conducted on Red Fork formation wells with bottomhole temperatures ranging from 225°-250°F. The fracturing applications and techniques in this area had historically provided lower than expected posttreatment productivity and a rapid decline rate, suggesting that the fracture conductivity were less than optimum. Joint efforts of the operator and service company, utilizing state-of-the-art fluids, breakers, and design methodologies, were employed to optimize well productivity. The case histories of hydraulic fracturing treatments and subsequent production performance of five offset wells are analyzed and presented. Average incremental production rates were significantly improved through application of the new technologies, clearly demonstrating the effectiveness of the modifications.
Production Automation System For Gas Lift Wells
Authors: Cooksey Andrew , Pool Mike
Published: December 2007

Economic conditions in the gas and oil industry have necessitated not only reductions in manpower and capital expenditure but also optimization of existing facilities. The approach that appears to offer the most viability for satisfying these needs is system automation. For this reason, technology in gas lift operation has directed its attention toward the development of modular systems that can automate operations at each wellhead and platform. Intelligent controllers can be used 1) with centralized master station direction or 2) as stand-alone products for automating immediate response to preset conditional parameters. In addition to reducing manpower requirements, intelligent controllers will further enhance gas lift operation by helping to increase the efficiency of continuous- flow gas lift operations. In addition, they can be used to automate load shedding that results from lift gas fluctuations. With automated systems, operators can now set up field-wide programs that provide optimum use of available lift gas with minimal manpower; this supports the operational direction encouraged by the economic climate of today's oilfield.

Production rates increase when normal gas lift flow rate set-point control is maintained at each well. In the optimization system described in this paper, the set point changes can be manually entered at the wellhead controller or from a central master station.

The local controllers, in addition to receiving set points from the master station, can intelligently change flow-rate set points in cases in which the line pressure is reduced. Orderly startup and shutdown functions control each gas lift well. These special functions, particular to operating gas lift wells, are designed to preserve the integrity of the downhole equipment. Additional advantages are realized from the more efficient usage of the lift gas and the immediate indication of problems that occur in standard production process equipment.
The Effect of an Initial Gas Saturation on the Performance of a Waterflood
Authors: Dykstra H.
Published: December 2007

The behavior of a waterflood is affected, among other factors, by the initial gas saturation at the start of injection. To illustrate this effect on oil rate and on the water-oil ratio (WOR), calculations were made with the Dykstra-Parsons(1) layered system model. Two cases were chosen, one for a high gravity oil with a low mobility ratio, and one for a low gravity oil with a relatively high mobility ratio.

The factors that effect the recovery of oil are described. The ideal situation for calculating a waterflood performance, would be that the values of all of the parameters to be used in the model correctly define the reservoir and fluid properties and the displacement process. The more closely the parameters define the system, the greater will be the confidence in the predicted results. If production history is available, a history match can be made. Certain parameters can then be adjusted to obtain a better match with actual performance before predictions are made of future performance. Examples are given for two waterfloods.

The fluid properties and saturation data used in the analysis were based on pressures obtained from depletion calculations to establish initial conditions prior to the start of the waterflood. For Case 1, a 40 deg API oil having an initial bubble point pressure of 3500 psia at 220 deg F was depleted down to a gas saturation of 30 percent. For Case 2, a 20 deg API oil having an initial bubble point pressure of 1500 psia at 130 deg F was depleted down to a gas saturation of 12 percent.

The results of the study show a substantial decrease in maximum oil rate and a substantial rise in the level of the WOR-recovery curve with increase in initial gas saturation. These types of results, showing the effect of an initial gas saturation, have not heretofore been published.