bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drill String Considerations for Gulf of Mexico'S Deepest Well (27,864')
Authors: Prater Terry E. , Everage S. DeWayne , Greenip John F. , Adams Burt A. 
Published: December 2007

Abstract
This paper chronicles the design analysis performed to drill the Gulf of Mexico's deepest well. With small diameter casing cemented in the hole, slim hole drilling plans for the record depth well were generated. The short fuse project required atypical slim hole drill string design to select a string with ample tension/torsion capacity, sufficient flow area for hole cleaning, and immediate availability. The final design was utilized in an "edge-of-envelope" environment with remarkable success. This paper discusses the factors involved in drill string selection and acceptance, actual field data, post well results, and future applications.
Pyro Technology for Cutting Drill Pipe and Bottomhole Assemblies
Authors: Cole James F. 
Published: December 2007

Abstract
In recent years, limited advances have been made in drill pipe recovery services technology. Depending on the size, weight per foot, and type of pipe stuck in the well, the options available to separate the pipe string, have remained the same for over a decade. These include:
String shot/back off Chemical Cutter Jet Cutter Metal Severing Tool
The most commonly used tool is the string shot/back off, which involves applying left hand torque to the pipe string at the neutral weight. The explosive produces and intense hammer blow and allows the joint to be unscrewed at the desired connection. The most difficult part of this procedure is determining the neutral weight at the depth of the back off attempt and the amount of torque required at that point.
The back-off is a preferred method because it leaves a clean top on the down hole fish. This saves time in the fishing operation, which is critical to a successful fishing job. However, as wells become more deviated or well conditions become more severe, the back-off method can become less effective.
This paper introduces new technology for disengaging pipe located above the point where the drill string assembly is stuck. The system uses a solid combustible mixture which produces sufficient heat to separate drill pipe, leaving a clean top on the remaining down hole fish. The sytstem is safe to store, transport and handle at temperatures up to 660°C. It's solid combustible mixture does not ignite due to pressure, shock or impact, under normal conditions.
The True Value Of Automated Rotary Directional Drilling Technology is Demonstrated on a Well Offshore Brunei
Authors: Ruszka Jon , Vos Anton , Otter Bert , Othman Osmera Bin Hj 
Published: December 2007

Abstract
The Iron Duke Field, offshore Brunei, Borneo is operated by the Brunei Shell Petroleum Company. Fourteen wells have been drilled in the Iron Duke area over the life of the field, with a high degree of local experience having been gained. One area of operations which has consistently been troublesome is that of performing controlled directional drilling. Following the recent introduction of Rotary Closed Loop System (RCLS) drilling technology, an in depth-study of offset well data was carried out to determine whether application of this technology was a solution to any of the common problems encountered. The results of the study showed that all of the identified problems could be eliminated through use of a Rotary Closed Loop Drilling System. A suitable well was identified as a trial for the system and tools were mobilised from Europe for use in the 8½" hole section. The results of the well clearly demonstrated many of the advantages in using this new technology, with the resultant hole section being of higher quality and delivered with a time saving of 55%.
This paper outlines the common problem areas identified from the offset data study. It shows how application of the new technology eliminated these problems and resulted in a step change in both drilling performance and wellbore quality.
A ‘Keep It Simple’ Approach for Managing Shale Instability
Authors: Tan C. P. , Chen X. , Willoughby D. R. , Choi S. K. , Wu B. , Rahman S. S. , Mody F. K. 
Published: December 2007

Abstract
An efficient ‘keep it simple’ approach to the management of wellbore instability in shales is presented. It takes into consideration the factors which determine whether conducting a stress-induced wellbore stability analysis would be sufficient or complex time-dependent drilling fluid-shale interaction and thermal stress mechanisms need to be taken into account in the development of a mud weight program.
A range of design and analysis tools required for wellbore stability analysis is described systematically. The tools include practical guideline charts for stability analysis, optimum wellbore profile and wellbore drillability, design charts of pore pressure change due to drilling fluid-shale interaction mechanisms, shale property database and correlations, and simple stress-induced and complex time-dependent wellbore stability analysis software.
The application of all the tools is demonstrated through three field case studies to develop strategies to control shale instability in wells drilled in the North West Shelf of Australia. The tools provide a practical means of optimising the approach in developing the solution, including drilling fluid design (weight, type and chemistry), to manage shale instability efficiently.
Conductor Sharing—A Viable Alternative to Multilaterals and Slot Recoveries
Authors: Dharaphop J. , Borisutsawat C. , Chaisangkha V. , Boyne K. , Thouvenin E. 
Published: December 2007

Abstract
Conductor sharing allows two or more wells to be drilled from a single drilling slot, expanding well capacity of a platform at minimal cost. As limited slot availability is one of the driving forces behind the selection of multi-lateral wells, conductor sharing is a possible alternative. Experience with both technologies on the Bongkot field has proved that conductor sharing can offer greater operational flexibility than the multilateral alternatives at equivalent costs.
In multi-lateral wells full isolation of the drains requires expensive equipment and complicated procedures. These complexities increase the cost of well construction and increase the risk of partial or complete failure to reach the objectives. With the multi-lateral on production the costs and risks associated with well servicing operations are also higher.
Drains drilled from shared conductors are operated independently during drilling, completion and production phases. Proven technologies can be used at all stages of the well life, minimizing both equipment costs and the risks of failure. Initial well costs are therefore lower while maximizing production flexibility. Well servicing operations are reduced in both frequency and complexity.
To date on the Bongkot field conductor sharing has been used in seven slots for gas producing wells and horizontal oil wells. A multi-lateral well was previously drilled on the field allowing a direct comparison of the two methods. The cost differential of drilling and completing two horizontal wells from a shared conductor and one multi-lateral well was less than 10%.
As a further benefit, the minor initial investment required to convert a slot to a shared slot at the time of the 1st well installation, will in future eliminate the need for costly and risky slot recoveries, in order to tap unproduced reserves reachable from mature fully drilled Work Platforms, hence increasing the amount of recoverable reserves.
The paper describes the principles of the conductor sharing, the perceived advantages over multi-lateral wells and slot recovery, and presents results from multi-lateral, recovered slot and shared conductor wells drilled to date.
Buying and Selling Producing Oil and Gas Properties: The Norms in the Data
Authors: Lohrenz John 
Published: December 2007

Abstract
Data from actual purchases of producing oil and gas properties over the past decade were collected. For each purchase, 5 data elements were captured: (1) Purchase price, (2) Recoverable oil reserves, (3) Recoverable gas reserves, (4) Oil production rate, and (5) Gas production rate. Quantitative norms in these purchase data are shown as well as distributions about the norms. The results are then used to show how comparisons can be made for specific, recent purchases not in the data base against the norms.
Comparing Three Methods for Evaluating Oil Projects: Option Pricing, Decision Trees, and Monte Carlo Simulations
Authors: Galli A. , Armstrong M. , Mines de Paris Ecole des , Jehl B. 
Published: December 2007

Abstract
Option pricing, decision trees and Monte Carlo simulations are three methods used for evaluating projects. In this paper their similarities and differences are compared from three points of view:- how they handle uncertainty in the values of key parameters such as the reserves, the oil price and costs; how they incorporate the time value of money and whether they allow for managerial flexibility. We show that despite their obvious differences, they are in fact different facets of a general project evaluation framework which has the static base case scenario as its simplest form. Compromises have to be made when modelling the complexity of the real world. These three approaches can be obtained from the general framework by focussing on certainty aspects.
Prediction of Short-term Natural Gas Prices Using Econometric and Neural Network Models
Authors: Reiter Doris F. , Economides Michael J. 
Published: December 2007

Abstract
The development of the natural gas industry in the last decade was shaped by deregulation from federal oversight. This created an environment with fierce competition but also highly volatile spot prices, which exposes market participants to a considerable price risk. Risk management becomes vital in such a business environment. An integral part of risk management besides understanding the market’s fundamentals is to develop quantitative models which help predicting gas prices or price changes based on market information. Current price prediction focuses on long-term equilibrium price forecasts, but does not give any information about the day-to-day volatile behavior of spot prices. For long-term delivery contracts this might be sufficient, but for trading on a speculative basis more accurate information about price movements is sought. This paper shows that a solution for day-to-day prediction of spot prices is feasible. The most appropriate models in achieving this task were selected to be an econometric model with lagged variables and a neural network model. As volatility of the spot price is usually higher in the winter and seasonality in the consumption pattern is given, the model was developed based on data for the winter. The performance of both models was tested in a simulated trading scenario and compared to a scenario where perfect prediction quality was assumed. The results showed that both models were profitable during the time span the test was conducted. The neural network showed better results than the econometric model. In comparison to the best case scenario the results were very pleasing. These models can provide a valuable, supportive tool for trading of natural spot gas in a speculative environment.
Scenario Selection for Valuation of Multiple Prospect Opportunities: A Monte Carlo Play Simulation Approach
Authors: Kokolis George P. , Litvak Boris L. , Rapp William J. , Wang Ben 
Published: December 2007

Abstract
This paper describes an approach for simulating and appropriately valuing complex E&P projects containing multiple prospects. The approach uses a Monte Carlo simulation model, which is described, that simulates a play containing multiple prospects. The play evaluated can consist of pure exploration prospects, or may contain a mixture of discovered reserve opportunities (DRO's) and exploration prospects. Resource (reserve) size distributions, dependent geologic prospect risks, risk tolerance, stand-alone commercial threshold sizes, and tie-back thresholds are some of the key drivers of the play simulation.
The simulation generates expected commercial reserve levels and commercial risks for each prospect included in the play, as well as an overall project commercial reserve distribution and risk level. In addition, and more importantly, discrete development scenarios for high (P90), mid (P50), and low (P10) reserve cases can be generated. These development scenarios can then be used to determine a valuation range for the prospects.
The value of this approach is that it provides a consistent methodology to generate a range of discrete development scenarios that span the reasonable range of project success - case expectations. Development plans for those scenarios can then be applied and the scenarios can be deterministically evaluated to determine the range of the project's economic value. This hybrid approach of a stochastic play model combined with deterministic economic evaluations avoids some of the common pitfall of most pure stochastic or pure deterministic approaches.
Methodology is also described for logically grouping discrete prospects into "super-prospects" for the purpose of evaluating projects that contain an unwieldy number of small prospects.
Formation Evaluation Masked by Mud Invasion
Authors: El-Wazeer F. , Haggag M. , El-Farouk O. 
Published: December 2007

Abstract
Mud invasion affects most data acquired by logging tools which in turn affects formation evaluation. Historically, correction programs have been designed to compensate for this effect. With the introduction of Logging While Drilling (LWD) it has became possible to gather data before invasion masks reservoir properties.
Complete logging suites run in a number of wells on-shore Abu Dhabi allowed quantification of invasion effects using logging while drilling, logging while pulling out and wire-line logs. The comparisons, in both horizontal and vertical holes, indicated considerable differences in resistivity and nuclear measurements between runs. The variations depend on time of exposure, porosity, differential pressure and permeability. In horizontal wells where exposure time is longer, resistivity values were greatly reduced by invasion, to the extent of masking true formation resistivity which could not be corrected through known algorithms.
These phenomena may explain differences between log interpretation and test results. In some cases, dry oil was tested in formations that calculated high water saturation, up to 70%, based on logs affected by invasion. It became apparent that the invasion profile had different characteristics in gas zones, providing a new tool for gas detection. In addition, monitoring invasion processes is a useful method for fracture detection by overlaying while-drilling and after-drilling resistivity curves. Fractured zones detected by this method were confirmed by bore-hole imaging techniques. This study proposes a complete framework for evaluating invasion effects leading to improved reservoir description.
Regional Temperature Gradient: A Key To Tilted OOWC
Authors: Stenger B. A. 
Published: December 2007

Abstract
The Arab-D member – Arab formation (Upper Jurassic) – is one of the most prolific oil reservoirs in Saudi Arabia. Located onshore in the Eastern Province and offshore in the Arabian Gulf waters, many huge oil fields have been discovered since the forties. In addition to their size, several Arab-D oil fields present another similarity: the original oil water contact (OOWC) is apparently tilted.
Several theories have been advanced in the past, but none were able to account successfully for the tilt.
The lack of flank wells intersecting the OOWC in a clean reservoir section makes it even more difficult to ascertain the origin of the tilt. In addition, special care must be devoted to avoid using information coming from edging wells in areas where crestal production has already been high, resulting in a dynamic OWC, not the OOWC.
A new model has now emerged to account for the observed tilt of the OOWC. This model is based on the existence of a higher geothermal gradient close to the Dammam dome area (Saudi Arabia Eastern Province). Studies are underway, using SAUDI ARAMCO multi-disciplinary teams to integrate these facts in a tectonic model of the area.
For the Ghawar field, it has been shown that the observed tilt of the OOWC can be explained by the evolution of the regional geothermal gradient, and by an inflow of fresher water on the western flank of the Haradh area. What was thought before to be a hydrodynamic-related tilt is now interpreted as a pure static equilibrium with varied fluid densities.
The tilt of the OOWC has been back calculated and found to be in good agreement with the values measured in key wells. Applications of this particular type of static equilibrium in reservoir simulation will be presented to conclude this integrated approach, which was successful to establish a consistent picture of the Ghawar OOWC tilt.
Case Study: The Role of Simulation in Supporting Reservoir Management
Authors: Al-Yousif A. M. , Al-Hasan A. H. 
Published: December 2007

Abstract
Two newly drilled high slanted wells produced water pre-maturely. The two wells were completed with good clearance from the oil /water contact. Openhole logs of the two wells showed water-free oil zone. Offset wells located downstructure and towards the flanks produced water-free oil from the same zone. Down structure newly drilled conventional well showed a full oil column from the top to the base of the reservoir.
With the above description of the problem, the following questions need to be answered:
How did these two high slanted wells produce water very pre-maturely? What was the production mechanism? Will it be feasible to drill more wells down structure from these two wells and towards the flank? And, if feasible, what type of completion (conventional or high slanted / horizontal) should the proposed wells have?
Simulation was used as a tool to investigate the above-described case in an attempt to give possible answers to the above expensive questions.
The study considered a three-dimensional sector model. The model was finely gridded and multi-layered to provide aerial and vertical tracking of fluid movements required to reasonably assess reservoir performance.
Results of the study: (1) assisted in explaining the early water breakthrough in the two high slanted wells, (2) gave guidance to reservoir management engineers for the proposed future drilling of five wells, (3) recommended optimum rates for the wells in the study.
Pinpointing Fluid Entries in Producing Wells
Authors: Rounce Justin , Lenn Chris , Catala Gerard 
Published: December 2007

Abstract
In recent years there has been significant increase in understanding multiphase flows in producing oil wells. This has shown that evaluation of production can be challenging when conventional production logging measurements are used. Often, only qualitative interpretations can be made, leading to remedial work recommendations based on partial answers, even in vertical wells.
In this paper we summarize the most current understanding of multiphase flows, which have lead to the development of a new production logging measurement and interpretation technique, in which global and local sensors are highly integrated. The resulting new production logging technology has, for example, successfully been conveyed in very high-angle wells, without the assistance of coiled tubing, and major new measurements have been taken as close as 1 ft from the bottom of the well. Furthermore, such technology allows better diagnosis and quantification of even minor, but economically significant, oil entries completely undetectable by conventional production logging tools.
Field examples are presented, demonstrating the value of these new measurements. Unambiguous detection of large- and small-scale oil entries in addition to unwanted water entries with pinpoint accuracy are shown. This leads to confident remedial actions and more accurate evaluation of field economics with better estimation of reserves and sweep efficiency, previously outside the resolution of traditional measurements.
Dimensionless Groups for Interpreting Proppant Transport in Hydraulic Fractures
Authors: Al-quraishi Abdulrahman A. , Christiansen Richard L. 
Published: December 2007

Abstract
The significance of convection, density driven flow, for placement of proppant during hydraulic fracturing has been discussed in the literature. In this study, small glass model was constructed to simulate a fracture. Newtonian and non-Newtonian fluids with controlled density differences were used and variables such as density difference, viscosity, fracture width, proppant concentration, and flow rate were considered. Proppant placement efficiency in the experiments was interpreted with two dimensionless groups. One group compares viscouse and gravity effects and the other compares convective and dispersive effect. The experiments showed that the pattern formed by the boundary between the displaced and the displacing fluids is very simmilar to that observed in much larger models. It has been noticed that convection is very significant even with very small density differences. As viscouse to gravity ratio increases by reducing gap width or increasing the displacing fluid viscosity, the effect of convection becomes less and proppant placement efficiency tends to increase resembling that of Craig et al.1 for gravity override in reservoirs. The effect of convective-dispersive group was found to be small compared to the viscouse to gravity group. The experiments conducted were simulated using an excutable code (GOHFER) and the results indicate that proppant slurry transport can be accurately modeled.
Increasing well life cycle by eliminating the multistage Cementer and utilizing a Light Weight High Performance Slurry
Authors: Mukhalalaty Talal , Al Suwaidi Abdullah , Shaheen Mansour 
Published: December 2007

Abstract
Trapped gas and oil between production and intermediate casing (abnormal annulus wellhead pressure) has been globally recognized as one of the serious challenges facing drilling and production operations. The issue is becoming serious since wells are aging and the integrity of the casing portion below well head is increasingly affected by the shallow water corrosive environment. The potential safety and environmental hazards of the abnormal annulus pressure, have encouraged ADCO to review the current drilling and cementing practices, aiming at minimizing the impact of the problem, thus improving well life cycle and reducing the frequent work-over interventions. The general guide lines set to resolve the problem were by eliminating potential leakage paths in the completion and casing strings, and by emphasizing on the quality of the primary cementing, specially of the production casing string.
Cementing casing in single stage utilizing lightweight slurries has been the technique used in ADCO to improve 9 5/8" primary cementing. The new cementing methods have been found operationally and economically feasible. Summary for the recent case histories are presented in this paper, along with the conclusions and recommendations.