bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stimulation Design and Post Fracture Production Analysis: A Tight Gas Sand Case History
Authors: Larkin S. D. , Brown E. K. , Bazan L. W. , Manuel G. W. , Becnel J. L. 
Published: December 2007

Abstract
This manuscript will outline the stimulation design criteria for wells in the Lobo Trend in south Texas and fracture design changes based on post fracture production analysis using commercial software.
Production data will be modeled with the corresponding fracture geometry. Model results will be used as the benchmark to discuss fracture design changes and the effect on well performance. Case histories will focus on tight gas sands with reservoir quality ranging from 0.05 to 1.5 md with some pressure depletion. Multiphase flow effects in areas with higher water production will be investigated. Some discussion will focus on the details of calibrating fracture model inputs using open hole logs, radioactive surveys, sonic logs, production logging tools and mini-frac analysis.
Results comparing post fracture well production, utilizing a pseudo 3D fracture design model and industry available production matching models, will show the effects of permeability, pressure depletion and multiphase flow effects on well performance. Understanding this information will allow the stimulation design engineer to better predict how geometry and fracture conductivity will alter well performance under varying reservoir conditions. With this knowledge, the engineer can better design ‘it for purpose’ treatments, including those that may require extreme design changes in order to improve gas reserve recovery.
Knowledge Management and New IT Architecture Will Maximize Upstream Value-Creation
Authors: Gibson John 
Published: December 2007

Abstract
Long before the oil price collapse of 1998, the petroleum industry has been on a roller coaster ride that is not over yet. Despite the current high oil prices, slowly rebounding energy stocks and a general atmosphere of optimism, our industry faces a number of serious challenges in the coming years.
For one thing, our workforce is rapidly aging and enrollments in petroleum-related university programs are at record lows. So, we are facing an impending shortage of intellectual capital, which will impact our ability to make wise decisions. Knowledge management, therefore, must become a way of life, not just another buzzword.
Furthermore, energy companies are still not as consistently profitable as other investment alternatives in the marketplace. The oil and gas industry must leave no stone unturned in its quest for greater efficiency and productivity. New Internet-based IT architectures will be necessary to enable us to sustain and grow profitability, not just at $25 per barrel or $4 per Mcf, but at any price.
Part 1 of this paper explores the "people problem" and issues of knowledge management in more detail. Part 2 will describe an emerging IT infrastructure that promises to lower costs and maximize both efficiency and value industry-wide.
Geologically Oriented Geostatistics: an Integrated Tool for Reservoir Studies
Authors: de Lastang A. Pelgrain , Cosentino L. , Cabrera J. , Jimenez T. , Bellorin O. 
Published: December 2007

Abstract
Geostatistics has entered a new age. Until few years ago, geostatistics could still be considered a leading-edge technology, developed and applied by a handful of specialists. Today, geostatistics is routinely applied to most of the reservoir characterization projects worldwide, providing the ‘quantitative geology’ support needed in the reservoir simulation phase.
This paper describes how a geostatistical model can be built by integrating all the information generated in the individual disciplines, namely Geophysics, Petrophysics, Sedimentology, Stratigraphy and basic Reservoir Engineering. This approach guarantees the internal consistency of the reservoir study and provides a robust model to be upscaled in the forward simulation phase. The information contained in the 3D geological model can also be averaged and exported to a conventional mapping algorithm, thus providing a consistent set of traditional 2D maps of reservoir properties (Net to Gross, net sand, porosity, permeability).
A case study is presented, relevant to a Venezuelan oil and gas condensate field. The geostatistical model uses almost 400 wells and includes a stratigraphic section almost 3000 feet thick, with 60 productive sands and about 500 reservoirs. In this field, where a conventional map-based approach would have been a long and cumbersome job, the complete geostatistical model has been built and input to the simulator in less than 6 months. In such a context, geostatistics represented a fast and efficient tool for the integrated study.
Application of Multilateral Wells in Solution Gas-Drive Reservoirs
Authors: Rivera Nestor , Kumar Amit , Kumar Arun , Jalali Younes 
Published: December 2007

Abstract
We present in this paper a reservoir analysis of the application of multilateral well technology in single-target structures. We focus on the correspondence between reservoir type and established multilateral well technologies. We consider a wide range of permeability fields and fluid characteristics, but consider only the depletion or solution-gas drive mechanism. We suggest that the behavior of multilateral wells under other drive mechanisms is fundamentally similar to that under the solution gas-drive mechanism. We conclude that with respect to the application of multilateral well technology, where the objective is attaining favorable production performance, there are essentially two classes of reservoirs – those that require maximum exposure to the wellbore and those that require limited exposure. The traditional unsealed multilateral technology (levels 1-4) is appropriate for the first class, while the recent sealed junction technology (levels 5-6) is appropriate for the second class. We explain precisely why that is so, and what criteria can be used to select the appropriate multilateral level within each reservoir class. We substantiate our conclusion by benchmarking the performance of multilateral wells with horizontal wells. Also we note that the correspondence between reservoir and multilateral technology types seems consistent with the economic feasibility of these solutions.
Use of Geostatistical Modeling and Automatic History Matching to Estimate Production Forecast Uncertainty–A Case Study
Authors: Bennett Fletcher , Graf Thomas 
Published: December 2007

Abstract
Determining production forecast uncertainty from simulation models is one of the major challenges facing reservoir engineers. Often a single deterministic model or geostatistical realization with a single permeability transform and set of relative permeability curves is taken from a history match and then used to prepare forecasts. Geostatistical realizations inconsistent with the chosen set of permeability transforms or SCAL data are discarded. This leads to troubling questions as to the uniqueness of the history-matched model, the uncertainties associated with the forecasts and the magnitude of risk for reservoir development.
In this paper these concerns are addressed with an approach that uses automated history matching based on the gradient method to obtain a history match for more than one geostatistical representation. This approach takes into consideration both geological uncertainties and uncertainties in pressure and saturation matching parameters. In addition, the approach is fast and can be partially automated to complete history matches and forecasts of stochastic models as they are updated with the drilling of additional wells. It can also be used to reject realizations that require absolute or relative permeabilities outside their range of uncertainty or lead to large differences between observed and simulated data.
For the example reservoir - a fluvial-deltaic system in the eastern part of Venezuela, nine geostatistical realizations composed of 2.6 million cells each were generated, based on the range of structural interpretations and static parameters that could be expected. These realizations were then upscaled to 90,000 cell models and history matched in parallel. The automated history matching procedure involved the determination of the gradient sensitivity for key absolute and relative permeability parameters and subsequently the regression on the most sensitive and independent of these to obtain a minimum of the objective function. The realizations that resulted in best matches of field pressure and water production were brought forward to produce forecasts that resulted in an estimate of uncertainty for various field development options.
Optimization Study for the Offshore Platform Inspection Strategy
Authors: El-Reedy Mohamed A. 
Published: December 2007

Abstract
The optimization study of the inspection plan for the offshore structure platform is presented based on the probability of failure of the tubular joint under axial tension at yield.
The probabilistic study is considering the effect of corrosion on the capacity of the tubular joint. Observations and modeling of general corrosion of tubular joint are described. The probability of failure based on the ultimate capacity of the tubular joint under corrosion effect is determined using Monte-Carlo simulation technique.
An optimization model is formulated taking into consideration the probability of failure, the interest rate, periodic inspection cost and the minor cost repair.
The probabilistic analysis shows that, the probability of failure is reached to the maximum value after three years. Therefore, it may be concluded that the corrosion parameter is an important factor in the safety of the offshore structures and the proposed optimization formula can be applied to suggest an optimal inspection strategy assuming a constant inspection interval.
Improved Oil Recovery by Flank Waterflooding in the Lagunillas 07 Reservoir, Venezuela – A Case Study
Authors: Agbon I. S. , Ramones M. , Chang R. , Patniyot S. , Chek-Yan N. 
Published: December 2007

Abstract
The Lagunillas 07 reservoir is located on the eastern part of Lake Maracaibo in Venezuela. The reservoir contains the Laguna formation, the Lagunillas formation and the La Rosa formation. The sands are of the Miocene age, poorly consolidated, well sorted and fine-grained with an average thickness of 86 ft. The oil had an 18 API and a viscosity of 21 cp at initial conditions. Oil production began in 1926 and more than 1,000 wells have been drilled. By December 1999, 36.7 % of the initial oil in place had been produced. Flank waterflooding, at an average water injection rate of 100,000 stb per day, was introduced for pressure maintenance purposes in 1984. Cumulative water injected was 558 million barrels by December 1999.
This paper evaluates the flank waterflooding project in the Lagunillas 07 reservoir. The net oil recovery due to the flank waterflooding is estimated. The real time water front movement is determined with a front-tracking technique that uses fluid production data. The movement shows water fingering due to reservoir heterogeneity. A good match is obtained when the water front movement is cross-correlated with the petrophysical properties of the reservoir. Finally, the impact of the flank waterflooding on recovery factor is highlighted.
The paper concludes that a net oil recovery of 17 million barrels can be attributed to the flank waterflooding from 1984 to 1999. A net oil recovery of 160 million barrels is expected if the flank waterflooding is continued until 2019. The flank waterflooding is therefore considered a success. A future development plan is proposed for the reservoir.
Application of New Generation Rotary Steerable System for Reservoir Drilling in Remote Areas
Authors: Gruenhagen Hartmut , Hahne Ulrich , Alvord Graham 
Published: December 2007

Abstract
This paper describes the design criteria and operational experience with a new, second-generation Rotary Closed Loop System (RCLS). Rotary Closed Loop Systems are clearly revolutionizing the way in which oil & gas wells are drilled. During the past 5 years the technology has emerged from prototype status to a standard application in locations with good infrastructures such as the North Sea and the Gulf of Mexico. In remote areas with more challenging logistics such as West Africa, Asia Pacific, and South America, the use of rotary steerable technology has been very limited.
Based on the accumulated experience with a leading system, a new generation of Rotary Closed Loop System has been introduced specifically for remote operating areas. These areas have a relatively poor infrastructure, difficult logistics and some experience extreme environments.
The paper describes the technological challenges that had to be overcome for the standard application of Rotary Closed Loop Systems in remote areas and illustrates the advantages to the oil & gas industry with some exemplary case histories.
Rig Management System (RMS II)
Authors: McKechnie Bob , Gardner Kenny , Dawson Bob 
Published: December 2007

Abstract
Maintenance standardization and optimization are critical factors in the success of any pro-active maintenance organization. Continuing developments in maintenance practices have brought a growing awareness that the implementation of a well-planned Reliability Based Maintenance Strategy (RBMS) can result in reduced unplanned downtime for drilling rigs and equipment.
Still, the most significant development for maintenance management in recent years has not been the wealth of new techniques and practices. Instead, it has been the gradual acceptance that maintenance need not be a necessary evil, but that a carefully planned, information-based maintenance strategy can be a fundamental factor in the success of the organization.
Pro-active maintenance practitioners are familiar with the term "the right amount at the right time", but what is the right amount, and when is the right time? The real challenge to the empowered maintenance professional, is to convert textbook theory into workable practice, and to do that, he must have the right tools for the job.
BOP Subsea Hydraulic Accumulator Energy Availability, How to Ensure You Have What You Need
Authors: Sattler Jeffry P. 
Published: December 2007

Abstract
Blowout Preventer (BOP) hydraulic control systems have long used accumulator bottles to deliver energy to function equipment more quickly than the pumps can alone. With the advent of subsea stacks, people recognized the need to modify these accumulators and the operating procedures to reflect the effects of hydrostatic head. The continued expansion into deeper waters, coupled with an increase in the system operating pressure for the latest generation rigs, has necessitated new methods of calculating energy available in subsea accumulators.
Traditional accumulator calculations and regulatory standards assume isothermal (constant temperature) ideal gas behavior. Operating in deeper water and advances in shearing requirements and tubular strength affect the pressure required to operate BOPs and have precipitated the need for more accurate calculation methods that more closely model real gas behavior. At the same time, API standards committees recognized the inaccuracies associated with these assumptions, and provided adequate safety factors in their standards to compensate for the water depths of the day. However, there are no guidelines at this time for how much energy should be supplied in accumulators subsea. Additionally, changes to the operating environment today, combined with new operating sequences, e.g. deadman, autoshear, have made a good understanding of the science pertinent to the operation of these accumulators a mandate.
This paper reviews the impact of subsea accumulators on fifth generation floating drilling rig BOP operation, fluid requirements such accumulators must deliver for various operating cases, and different methods of calculating volume and pressure requirements for such fluid. It concludes with recommendations to utilize corrected maximum required shearing pressure for the Pmin of usable volume calculations, coupled with corrections to ideal gas based on adiabatic expansion for the best estimation of energy stored in subsea accumulators.
Core Competency, Core Business and Drilling Performance
Authors: Proehl Thomas Strenger 
Published: December 2007

Abstract
Objective, transparent examination of actual drilling performance data and trends is curiously lacking. This paper defines two categories of drilling actors, risk-management contractors and best-efforts operators. It also defines the terms "core competency", "core business", and "drilling performance". A cardinal grading system for wells, based on grade point averages used in schools is presented. The system is objective, simple, and universally applicable. The total well grade is based on planned objectives versus actual accomplishments, planned versus actual time, and planned versus actual expenditures.
Two sets of 50 wells each were graded. One set was drilled on a risk-management basis, the other on a best-efforts basis. On average, the risk-managed wells graded 2.66/4.00 and the best-efforts wells graded 1.60/4.00. The composite risk-managed well was 1.81% over planned days and 2.03% over planned dollars. The composite best-efforts well was 26.57% over planned days and 2.37% over planned dollars.
The performance difference is analyzed. Personnel, technology, process issues, and economic theory are considered as root causes. It is concluded that wells drilled by organizations whose core competence is a core business grade higher than those drilled by organizations whose core competence is not a core business. The evidence also supports the conclusion that risk-management contractors plan and drill wells more efficiently than best-efforts operators. Finally, economic risk and reward principles explain most of the performance differential.
Pre-drill Seismic Predictions Platform (Pore Pressure, Fracture Gradient, Lithology, and Pore Fluids) Effectively Used as a Well Planning Tool by a Multi-Discipline Deepwater Operations Team
Authors: Littleton Rodney , Cody Rick , Landreth John , Greve John 
Published: December 2007

Abstract
Pioneer Natural Resources’ multi-discipline Deepwater Exploration Operations team recently planned and operated the company's first deepwater (4946’ WD) GOM well, Argo #1, using a Life Cycle Analysis (LCA) planning process. As the closest offset well was 25 miles distant it was imperative to mine the maximum amount of pre-drill information from the pre-stack seismic data set.
The team wanted a 3D seismic-based platform that would generate multi-discipline output for use throughout planning and drilling of the well. Of particular importance was the need for a tool that could be used onsite for real-time lithology, porosity, and fluids correlation and pore pressure and fracture gradient prediction. The multi-discipline solutions were provided in SEGY files for the Geophysical and Geological (G&G) team members and graphical documents for the Drilling/Completion & Reservoir team members.
The seismic-based platform offered by the service provider was used successfully to plan, drill, and evaluate the well for the AFE'd cost. The service company provides two processes:
The first process, DrilSeis, is a new, fully automated pre-stack seismic velocity extraction algorithm that generates pore pressure and fracture gradient volumes.
The second process, LithSeis, is a pre-stack seismic-based petrophysical analysis that yields lithology, porosity, and possible hydrocarbon accumulations. LithSeis was used to aid in the confirmation of the prospective zones and to screen the shallow sediment section for possible "shallow water flow" SWF and shallow gas zones.1 Also, the pre-drill seismic pore pressure and petrophysical analysis (lithology, porosity, and fluids) provided the operator with the G&G and Engineering data that supported the approval from the Minerals Management Service (MMS) to eliminate the 20" conductor casing resulting in significant cost savings. The seismic solutions platform enabled the multi-discipline team to conduct cost-effective deepwater drilling operations.
Advanced Slip Crushing Considerations for Deepwater Drilling
Authors: Sathuvalli U. B. , Payne M. L. , Suryanarayana P. V. , Shepard J. 
Published: December 2007

Abstract
Deepwater drilling trends are moving towards deeper water depths as well as deeper exploration horizons and reservoirs below the mudline. These trends have created various operational and well design challenges. This paper addresses a serious problem pertinent to the design of landing strings and drill strings for deepwater operations. These strings are designed to run long and heavy casings, tiebacks, or liners (typically including deep intermediate and production tubulars). The total weight of these strings may approach or exceed 1,000 klb&lt;SUB&gt;f&lt;/SUB&gt; at the mudline. Adding in the additional weight of the landing string back to the rotary results in a serious design problem regarding both the landing string itself and the handling equipment. Slip-based handling systems work well in most instances, but lead to bi-axial loading from the tension and radial loads exerted by slip inserts. As a result of biaxial loads, the axial load rating of the landing string is reduced. The current understanding of slip crushing phenomena is based on testing and modeling work dating to 1959. This paper examines recent tests in the light of more advanced models and presents an improved understanding of slip crushing loads.
Selective Coiled Tubing Access to All Multilaterals Adds Wellbore Construction Options
Authors: Wortmann Henry , Peixoto Luis Felipe , Leising Larry , Bunaes Christan , Nees Ejnar 
Published: December 2007

Abstract
This paper describes the ongoing development of a new lateral reentry system that provides access to all levels of multilateral wells. The inability to selectively enter Level 1 and 2 lateral extensions (classifications of the Technical Advancement of Multilateral wells, TAML) has traditionally limited rig-based and rig less coiled tubing operations in these wells. Although coiled tubing as a means to work in live wells offers distinct advantages in the late stages of well construction, until recently no reliable coiled tubing reentry technique was available.
The new system design includes a reentry bottomhole assembly (BHA), which consists of a surface-controlled orienting tool and a controllable bent sub. The system identifies the window of the selected lateral before attempting reentry, and confirmation of successful identification and entry is visible at surface through a software-displayed pressure log. The technique does not require a wired coiled tubing string; the corrosion-resistant reentry tool is operated solely on flow and is conveyed with standard coiled tubing equipment.
Field examples are presented that demonstrate the success of this system in reentering a designated lateral on the first attempt for operations such as matrix stimulation and openhole formation wash treatments. Current developments that enlarge the scope of applications to wellbore logging are also described.
With the introduction of a new reentry technique, operations such as openhole formation washes, selective matrix stimulation, production logs and nitrogen kickoff operations can be performed on coiled tubing in live, flowing multilateral wells. The ability to access all levels of multilateral wells with coiled tubing adds a new planning and contingency option to the operator's and driller's decision matrix for the drilling and completion phase.