bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimating Productivity Using Petrophysical Data: Second Frontier Formation, Lincoln County, Wyoming
Authors: Link Michael A. , Stonecipher Sharon A. , Watson Robert W. 
Published: December 2007

Abstract
The Second Frontier Formation in the Emigrant Springs area is a moderately tight, gas producing sandstone reservoir with absolute permeabilities averaging less than 1.0 md. Well completion in the area involves setting casing through the zone, perforation of the casing, and stimulation by hydrofracturing. Well evaluation is typically accomplished using production history and decline curves. Further development in the area, in terms of step-outs and infill drilling, demands techniques for predicting well productivity using wireline log data obtained prior to the setting of the casing.
In an effort to quantify these values, a petrophysical analysis was performed. Open-hole well logs, sidewall cores, and specialized logs such as Combinable Magnetic Resonance (CMR) and Formation Multi Imager (FMI) were used to compute parameters such as effective porosity, water saturation and permeability. The relationships between these parameters and productivity indicators, such as initial production (IP) and estimated ultimate recovery (EUR), were then studied.
Furthermore, this analysis included a review of depositional environments in the area to identify any effects on production. This examination included petrographic analysis of drill cuttings, and the interpretation of FMI logs, which were then coupled to previous petrographic work that considered similar data from the same general area1.
Results indicate that the product of log-derived porosity, permeability, gas saturation and pay thickness are indicators of IP and EUR. Additionally, this analysis demonstrates that productivity indicators are strongly influenced by geometric, textural, and diagenetic characteristics of the reservoir rock (lithofacies) that are largely a function of depositional environment.
The Multiple Role of Unconventional Drilling Technologies. From Well Design to Well Productivity
Authors: Charlez Ph. A. , Bréant P. 
Published: December 2007

Abstract
This paper deals with new drilling technologies and is focused on their ability to reduce capital expenditure per barrel produced. During the last decade, they have greatly contributed both to improve production and reserves but also to decrease operational costs. TOTAL has been involved in these unconventional technologies all over the world and has used them for numerous original applications ERD to reach offshore reserves from onshore facilities (Argentina),ERD to test a marginal panel from existing offshore facilities (North Sea),Multilaterals to explore and delineate a blind zone (Libya), to improve production and to increase reserves (Libya, North Sea) or to revitalise a mature field (Middle East).
Unconventional drilling technologies play a key role today where conventional technologies are not fully efficient to keep development profitable. With time, smart drilling which appeared at the end of the 80’s has progressively become a must for any field development.
Application of the Diagnostic Plot Using a Derivative Based on Shut-In Time
Authors: Spivey John P. , Lee W. John 
Published: December 2007

Abstract
The conventional log-log diagnostic plot with pressure change and derivative with respect to the superposition time function has been applied with tremendous success in diagnosis of reservoir behavior by giving the buildup pressure response a shape similar to that of the drawdown response for a wide variety of different boundary conditions. However, this very success has led in a number of cases to overconfidence in its applicability and interpretation using an inappropriate reservoir model.
This paper discusses the use of a diagnostic plot comprising the pressure change and pressure derivative calculated with respect to, and graphed vs., shutin time. This form of the diagnostic plot requires a catalog of buildup pressure responses for different reservoir geometries and different producing times. This paper provides such a catalog for several common reservoir geometries.
Three field examples illustrating the application of the diagnostic plot using the derivative vs. shutin time are presented.
Water Induced Compaction in the Ekofisk Field
Authors: Sylte J. E. , Thomas L. K. , Rhett D. W. , Bruning D. D. , Nagel N. B. 
Published: December 2007

Abstract
Over 7.8 meters of seafloor subsidence has occurred at the Ekofisk Field in the Norwegian sector of the North Sea since the start of production in 1971. Full field water injection was initiated at Ekofisk on a limited scale in 1987. The surface subsidence is a result of reservoir compaction, which is considered primarily to be due to pressure depletion until the early 1990's and water weakening thereafter. Rock compressibility was input as a function of initial porosity and increasing net effective stress (i.e. declining reservoir pressure) in earlier Ekofisk studies. In 1994, under a voidage balancing reservoir management program, water injection was increased sufficiently to stabilize reservoir pressure. However, no reduction in surface subsidence rate was seen. This, in combination with other field and lab observations, led to the conclusion that water was weakening the reservoir chalk and necessitated revising the rock compressibility functions at Ekofisk to include the effect of additional compaction due to the water weakening.
The development and implementation of the water induced compaction functions at Ekofisk is presented in this paper. Rock compressibility is now input into the model as a function of initial porosity, net effective stress, and water saturation. As water saturation increases in a model cell due to water injection or water influx, the model cell transitions to a weaker stress-strain curve. The effect of increasing water saturation, and the resulting water weakening of the chalk, is that compaction and subsidence may continue in spite of stable or increasing reservoir pressure. Both laboratory and field data are presented which support the use of the water weakening functions. The development and calibration of these curves is presented, which includes the effects of fracturing, creep, water dispersion effects, hysteresis logic, and strain hardening. A comparison of the calculated and measured compaction and subsidence bowls is also presented.
Applications of Neural Networks in Multiwell Field Development
Authors: Centilmen A. , Ertekin T. , Grader A. S. 
Published: December 2007

AbstractA common field development task is the optimal placement of the wells. One of the key parameters in the success of a new well is its physical location in the reservoir. When several wells are planned hundreds even thousands of placement combinations must be considered in order to optimize specific production goals. The large number of degrees of freedom makes using a standard reservoir simulator to evaluate all these placement combinations prohibitively time consuming and expensive. This paper demonstrates a neuro-simulation technique that forms a bridge between an accurate reservoir simulator and a fully-trained predictive artificial neural network (ANN). The paper outlines how the coupling of soft and hard computing techniques allows for a rapid and efficient selection of well locations while maintaining reasonable accuracy. In this method, several key well scenarios are selected by engineering judgement and/or randomly. These scenarios are then evaluated using a numerical reservoir simulator. The simulation results form the basis for training an ANN. When the ANN is trained for a specific reservoir configuration, it forms a fast predictive tool for optimizing the locations of the new wells in the reservoir. Thousands of possible scenarios are evaluated using the ANN with an insignificant computational effort. Then, all the predictions are ranked and sorted to provide the best possible scenario for placing the new wells. It is the combination between ANN and genetic concepts that leads to an efficient optimization process. Simulated reservoir examples with various shapes, properties, and number of existing new wells are considered in the paper. The results of the paper demonstrate the effectiveness of neuro-simulation by reducing the computational effort and maintaining accurate predictive capabilities. The paper also presents the guidelines for using neuro-simulation to optimize the placement of the wells.
Reliable Electronics for High-Temperature Downhole Applications
Authors: Gingerich B. L. , Brusius P. G. , Maclean I. M. 
Published: December 2007

Abstract
This paper outlines the reliability improvements which can be made to down hole systems by a line of reliable high temperature electronics which have been developed for instrumentation and distributed controls on aircraft gas turbine engines. Testing of these components has shown long life capability of 5 years or more at temperatures up to 225°C. These same components form the electronics base for a data acquisition system that can be used in downhole permanent gauges installed during completion. As part of an ongoing effort to provide reliable high temperature electronics a statistical database has been developed to project failure rates for these components
Development of Remote-Controlled Dynamic Orientating System
Authors: Urayama T. , Yonezawa T. , Nakahara A. , Ikeda A. , Nakayama T. , Gleitman D. D. 
Published: December 2007

Abstract
Obtaining a smoother well bore path and reducing of drilling costs, through higher penetration rate and reduced trip frequency, are essential objectives of a technical innovation for horizontal and directional well drilling. In order to achieve these goals, a research project developing a remote controlled dynamic orientating system (RCDOS) for horizontal well drilling was organized and initiated by Japan National Oil Corporation (JNOC) in 1989. Originally, the project was composed of developing two sub-systems, a new deflection actuator and a new two-way telemetry system with a high bit rate. As the former could be used in combination with practical conventional mud pulse telemetry systems, it has lately become an independent target in the project. The deflection actuator is installed above a bit. The bending angle and bit tool face can be controlled independently and dynamically during the drilling process by the deflection actuator, from 0 to 1.5 degrees and 0 to 360 degrees respectively. Both tools for 8-1/2 and 12-1/4 inch bore holes have been developed. The deflection actuator is applicable for both rotary steerable and motor steerable drilling tools, and it consists of the following main components: communication terminal, seal mechanisms, pressure compensator, electromagnetic connector, reference stabilizer, high side sensor, RCDOS controller and bit drive-shaft bias unit. The bias unit is structured with Oldham couplings, electromagnetic clutches, positioning sensors for rotation angle detection, harmonic drive gears and double eccentric rings. It is a unique system for a drilling tool, because of its simple design principal and excellent performance. The RCDOS deflection actuator is the foundation of a new rotary steerable drilling tool currently under development (subject of future technical publications). In this paper, the fundamental work carried out for developing the RCDOS deflection actuator and verifying its performance is presented.
Engineering and Economical Concerns on Cost Recovery Treatment for Sharing Production Facilities
Authors: Shaheen S. E. , Bakr M. , EL-Menyawy M. 
Published: December 2007

ABSTRACT
Some oil / Gas fields are considered marginal and not economically exploitable under the approach of stand alone project. Therefore, sharing production facilities with other concessionaire shall considerably reduce capital and operating costs.
Nearby facilities can be utilized to process and accommodate the production of such marginal fields. The economical concerns of cost recovery treatment for the capital investments of the production facilities, versus operating expenses is vital in the development decision For marginal discoveries.
Development of oil fields depends on the expected revenue from such fields. This revenue depends mainly on; proven recoverable reserves, oil price and expenses. This is in addition to the applied legislations and agreements controlling the investors cost recovery and profitability. The utilization fee is subjected to a different cost recovery treatment according to the following: No capital investments are required (existing facilities)Sharing the cost of Constructing new facilities as a new asset.
The combination of the capital / operating fee is successfully applied in Egypt, where both owner(s) and user(s) are sharing the benefit of this methodology. The application of the above methodology is discussed in the paper, with special.emphases on the encountered problems and the reached solutions. Real field data and economical concerns are discussed in the paper for each of the following "sharing facilities" examples: Sharing pipeline network: Western pipelineSouthern pipelineMediterranean shore pipelineMain gas trunk pipelineThird party area at the Gulf of Suez.Sharing facilities in the Eastern Desert.Sharing facilities in the Western Desert.Sharing EI-Hamra terminal facilities.
The objective is not only to convert a non profitable project into profitable one, but also to maximize such profits, for the mutual benefits of both owners and users.
Prediction of Slug Frequency for Gas-Liquid Flows
Authors: Zabaras G. J. 
Published: December 2007

Abstract
During slug flow, knowledge of the slug frequency is essential for the gas -liquid receiving facility design as well as for predicting various slug flow characteristics such as slug length and pressure drop.
Various methods proposed in the literature for predicting the slugging frequency in horizontal and inclined pipes were examined. These included both empirical correlations as well as mechanistic models. Slug flow frequency data taken with an air-water system in a laboratory flow loop together with data from the published literature were compared to the predictions of the various methods. A total of 399 data points were collected covering pipe diameters from 1 to 8 inches and inclinations from 0 to 11 degrees above the horizontal. A total of eight published methods were compared to the data but none was found satisfactory. For this reason, the mechanistic slug frequency model of Taitel and Dukler (1976) was investigated in detail as an alternative unbiased prediction method. This model required the solution of the unsteady-state equations for mass and momentum by a finite difference technique. This numerical model gave satisfactory results at the expense of considerable computer CPU time. For faster slug frequency calculations a new correlation was developed utilizing all 399 data points. This resulted in 0% average error (bias) and 60% average absolute error. This correlation represents a significant improvement in slug frequency prediction accuracy over the other methods studied.
Multiphase Pumping for Heavy Oil: Results of a Field Test Campaign
Authors: Giuggioli A. , Villa M. , De Ghetto G. , Colombi P. 
Published: December 2007

Abstract
The paper describes the behaviour of a multiphase pump prototype installed in a heavy oil field of Eni -Agip in Sicily. The location is onshore, at the end of a 30 km. long pipeline connecting the production offshore platforms of Prezioso and Perla to the onshore oil process plant of Gela.
Main fluidodynamic features of the test site are: oil density 18° API, GOR = 120 Scf / bbl, Q liquid = 2500 bbl / day, W.C. = 10%. The dead oil viscosity at ambient temperature (17° C) is about 700 cP.
The prototype is based on the twin screw technology and has the following main features: -electric power;400 kW-nominal multiphase flowrate;18.000 bbl / day-fluid maximum allowable viscosity;1200 cP-maximum differential pressure;40 bars
In order to allow different flow conditions (pressure, temperature, flowrates, viscosity, void fractions) some auxiliary equipment were installed with the multiphase pump: an interconnecting skid, interposed between the pump and the production plant of Gela oil centre.a booster pump connected with the liquid outlet of the production separator and the interconnecting skid.
The tests were run at different heads, in the range between 10 and 33 bars, simulated by a choke valve in the interconnecting skid downstream the pump. The aspiration pressure was 3 bar.
The main problems encountered during the experimentation were related with the high paraffin content of the oil. The problem was sorted out substituting the fine mesh filter with a larger one.
The field tests ran for about 10 months with a record of 6400 running hours without any major problem. The main conclusion of experimentation is that multiphase pump is quite robust and reliable machine ready for industrial application even with heavy oils with viscosity up to 1200 cP, and void fraction up to 90-95%.
Skin Bypass Fracs: Proof That Size is Not Important
Authors: Rae Phil , Martin A. N. , Sinanan B. 
Published: December 2007

Abstract
Hydraulic Fracturing is probably the most widely used stimulation technique in the world today. Practitioners often have pre-conceptions that the process involves huge quantities of equipment and materials, often at vast cost. It is true that this is sometimes necessary. However, often all that is needed to produce effective stimulation – a meaningful increase in production that more than offsets the cost of the treatment and meets realistic production targets – is a conductive path through the region of near wellbore damage. This paper sets out to describe the processes involved in producing these skin-bypass fracs, and with the aid of computer simulations, to demonstrate the effectiveness of these treatments.
The methods detailed in this paper are designed to produce fractures with a maximum propped length of +/− 40 ft. Often these fractures will not completely cover the zone vertically. In spite of this, the data from the simulation studies clearly shows the effectiveness of these treatments. The results also show how variables such as skin factor, permeability, drawdown, net height, frac height, frac length, frac positioning, fracture conductivity, reservoir fluid properties and wellbore geometry influence the production increase. The conclusions drawn from these results are that in many wells effective stimulation can be produced by small, cheap hydraulic fractures, which employ the minimum of equipment and materials.
Skin-bypass fractures are cheap, use minimal equipment and are easy to operate. Furthermore, they are environmentally friendly. They are of benefit all over the world where limitations such as cost, deck space, deck loading and crane size often prevent "conventional" hydraulic fracturing. Skin-bypass fracturing is a viable alternative to matrix acidizing, particularly in formations where unfavourable mineralogy limits the use of conventional acid systems
Large Scale NORM/NOW Disposal through Slurry Waste Injection: Data Analysis and Modeling
Authors: Baker Brian D. , Englehardt John M. , Reid James D. 
Published: December 2007

Abstract
SPE 53821 described a process for NORM/NOW (Naturally Occurring Radioactive Materials/Non-Hazardous Oilfield Waste) remediation that has benefits to industrial, regulatory and general public concerns. For the process to be successful the method must be adequately monitored. Both surface and downhole data must be monitored with a "cradle to the grave" mentality to ensure that the economic success of the process translates to practical safety and long-term containment. This paper describes the monitoring process, data analysis and equipment that was used at the CNO#2, NDW (NORM Disposal Well) site in Fourchon, Louisiana. The paper also discusses diagnostics that could not be applied for various reasons due to locale and well conditions. We will provide a description of the process to date and the "learning curve" of Phase 2 of the remediation project.
Briefly, slurry waste injection is a process to inject slurry of 30-40% solids into a suitably characterized subsurface reservoir. In the case of NORM/NOW it merely means putting back the waste from where it came. The slurry is injected at 14-20bpm (barrels/minute) at 3900-4200 psia (BHP, bottomhole pressure) to 5000 feet. Typically, injection is initiated with clean water at or above fracture gradients. Injection is initiated as a step rate up to fracture pressure. Solid waste is then added to the process until the desired fluid properties are reached. The process is cyclic with 12-hour injection periods and 12-hour falloffs. The 12-hour cyclic process leads to a practical onsite operating scenario i.e. daylight operations with the same operating crew therefore minimising inconsistencies. Pressure data from both the injection and falloff periods are analyzed.
The data acquisition covers a) continuous recording of surface and bottomhole pressures, b) cased hole injection logs, c) surface injection rate and density measurements, d)daily reporting of surface parameters and unusual parameter events, "incidents". The data analysis covers a) step-rate tests, b) injection and falloff tests, c) cased hole log analysis. The open hole log analysis was described in the previous paper and will be further refined here. Several "incidents' are presented to illustrate abnormalities with this kind of subsurface injection.
New Solutions for Subsalt-Well Lost Circulation and Optimized Primary Cementing
Authors: Sweatman R. , Faul R. , Ballew C. 
Published: December 2007

Abstract
Drilling and cementing operations in certain subsalt wells in the Gulf of Mexico (GOM) and other areas have long challenged operators and contractors. These wells have thick, deep salt formations with shear zones just above and below the salt, resulting in high unexpected costs during drilling. Such formations are often referred to as "rubblized" or "disturbed" shale zones. One theory proposes that, during geologic periods, the movement of adjacent salt formations induces shearing stresses that cause deformation, brittle failure, and fracturing in the surrounding shales. Costly drilling problems in these zones are primarily caused by the narrow margins between pore and fracture pressures that result in severe lost circulation, hole instability, and high-pressure kicks. Some of these wells also exhibit uncontrolled gas flows and underground water flows. Many GOM deepwater blocks and shelfblocks have massive salt structures and potential hydrocarbon reservoirs, but the trouble costs and difficulties associated with drilling these wells have forced operators to plug and abandon some wells and completely avoid others.
Conventional lost-circulation and hole-stabilization treatments have been minimally successful in many subsalt wells. However, new wellbore-stabilization and cementing programs designed for subsalt wells can help ensure well control and integrity during drilling and production operations. This paper provides information for helping to improve subsalt drilling operations and lower well-construction costs. In addition, the failures and successes of lost-circulation treatments performed during drilling operations in shear and salt zones will be explained. Primary cementing operations that help provide costeffective zonal isolation and well integrity in these zones are presented, as well as best practices and proposals for cement-slurry design and mud displacement. Laboratory studies and cost comparisons that help justify replacing traditional materials and procedures with these cementing programs are also presented.