bluuebunny/crossref_metadata_2025 huggingface dataset:
An Investigation into the Technical Feasibility of Gas Injection into Fractured CHUC Reservoir in the Gulf of Mexico
Authors: Daltaban T. S. , Noyola A. , Trejo G. , Toledo R.
Published: December 2007

Many prolific oil reservoirs in the Mexico part of the Gulf of Mexico are fractured Carbonate systems. Their hydrocarbon production mechanisms generally include combination drive of aquifer, gas cap, and oil expansion and rock compaction. In some cases water injection is used as an additional means of energy. At late production life of these reservoirs where production decline is experienced, the usual problems are the lack of well potential, increased water production, or combination of the two. In such cases, it is imperative to find out efficient techniques of maintaining the pressure at reasonable levels for improving production while minimizing the water withdrawal rates.

One of the techniques to challenge the decline in production may be gas injection in the form of Nitrogen or re-injection of produced gas and additional make up gas when necessary. However, the possibility of premature breakthrough due to the fractures may result in low sweep efficiencies in these reservoirs.

This paper presents our investigation into the applicability of gas injection into Chuc reservoir located at Campeche Bay of Mexico, and that contains vugular and fractured Breccia and generally fractured sequences of Upper, Middle and Lower Cretaceous, which is typical to many reservoirs in the region. The methodology developed during this work is used to examine the relative contributions of pressure maintenance by gas injection; formation of secondary gas cap as an additional source of energy; immiscible and miscible displacement of the in situ oil; controlling the advancing water; molecular diffusion; reduction of the interfacial tension resulting in the improvement of relative flow characteristics of oil and gas; and gravity drainage, through a series of comparative case studies based on a real field data.

In our methodology, we developed a systematic procedure of attaining an appropriate characterization of the fluid PVT and molecular diffusion. We also demonstrated by a number of numerical experiments that even for simpler cases where miscibility is not possible, the simplifications in the modeling could result in severe under estimation of the reservoir performance. With the comparative case studies we present, we show that even under adverse reservoir heterogeneity conditions, if the process is carefully designed and some of the key reservoir parameters are taken into advantage, it is possible to increase the recovery well over the expected recoveries from the conventional techniques.

The methodology we designed and demonstrated in an application to real field cases is believed to be a useful vehicle for technical feasibility evaluation of other possible candidates in the region.
Analysis of Long-Term Performance in Tight Gas Wells: Field Examples
Authors: Arévalo-Villagrán Jorge A. , Ganpule Sameer V. , Wattenbarger Robert A. , Samaniego-Verduzco Fernando , Yañez-Mondragon Maclovio , Serrano-Lozano Jose R.
Published: December 2007

Production analysis of actual data shows long-term transient flow geometries with boundaries in a large number of gas wells which are produced from tight gas reservoirs. In this paper, long-term linear and bilinear flows caused by the presence of natural fracturing are discussed. Linear and bilinear flows as a source of matrix block drainage are investigated. Systematic methodologies to analyze production data for estimation of reservoir properties and OGIP under linear, bilinear, and boundary dominated flows in tight gas wells are described. Application of these methodologies in various actual tight gas wells from industrial sources and validation of these procedures by using numerical simulation are shown. Long-term transient flows and short fracture half-length in various post hydraulic fractured wells suggest the convenience to develop tight gas fields with a tighter spacing between wells.
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

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

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

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

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

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

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

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

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

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

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

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

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

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 klbf 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

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.
A Unique Experience of the Evolution of the Bit Technology and Application Experience through 20 years of Tunu Field Development, Indonesia
Authors: Yunus Fata , Besson Alain
Published: December 2007

The bit technology has evolved dramatically over the last 20 years through innovative techniques. New bit technologies have also allowed the introduction of improved drilling parameters. In the late seventies, the introduction of PDC bits generated impressive changes in the drilling performance. Later, in the eighties and the nineties, the continuous improvement of the understanding of the fixed cutter bit behavior, and the PDC cutter technology, opened a new era and consistently lead to better results. Alongside these striking events in the PDC bit development, the roller cone bit technology showed significant improvements in both the bearings and the cutting structures.

These results and the evolution of the technology are clearly illustrated in the bit performance experienced in the TUNU field, Indonesia. Over 200 wells have been drilled on TUNU since the exploration began in the mid seventies. Innovative designs were used for the optimization of the performance, the latest proven technologies were applied successfully. Over the past two decades, bit related performance has improved almost 10 times in the TUNU field.

The lithology of the TUNU field at the top of the intermediate section consists of soft to very soft, sand and Claystone. Through this section the hydraulic behavior of the bits was a key factor affecting their performance.

Below this zone, the formation is composed of medium strength sandstone and shale. Very hard dense dolomite and limestone stringers are encountered erratically throughout the interval. A high level of vibration, leading to catastrophic failures was typically observed throughout this zone.

The first roller cone bits run in TUNU gave run lengths no greater than 250 m, and an average ROP never exceeding 6 m/h. In the early eighties, the introduction of the first PDC bits led to spectacular results where more than 250% gains in ROP and meterage were achieved. In the early nineties, roller cone bits fitted with metal face seal and new cutting structures allowed, for a short while, to see roller cone bits drilling at lower cost than PDC bits. The first anti-whirl bits tripled the run length and doubled the ROP. Later, successful runs of steel body unbalanced bits provided an additional gain of 20% in the performance. Today, force balanced steel body PDC bits indicate that drilling this section with one bit and an average penetration rate of 45 m/hr is a reality.

Globally, the average penetration rate and meterage drilled per well improved almost by eight times and the trip time was also reduced drastically. In the intermediate section, the total saving per well is close to 1,000,000 US$. The cost per meter has dropped from 470 $/m to around 70 $/m. For the field, through the various phases of drilling, when comparing the performance of the first wells, and thanks to a continuous and active engineering follow up, more than 80 M$ were saved.
Innovative Low-Friction Coating Reduces PDC Balling and Doubles ROP Drilling Shales with WBM
Authors: Mat M. Rujhan , Zakaria Mohd Zulkifi Bin , Radford Steve , Eckstrom Darren
Published: December 2007

This paper describes the successful development and application of a new low-friction flouropolymer-based coating applied to PDC bits to minimize and often prevent balling while drilling shale formations. Successful laboratory testing, the results of several field runs and one field case study will be presented. The rate of penetration is shown to more than double in certain cases resulting in significant savings to the operator.
Unique Crosslinking Pill in Tandem with Fracture Prediction Model Cures Circulation Losses in Deepwater Gulf of Mexico
Authors: Caughron Douglas E. , Renfrow Douglas K. , Bruton James R. , Ivan Catalin D. , Broussard Paul N. , Bratton Tom R. , Standifird William B.
Published: December 2007

Even in routine applications, the safety, economic and technical problems associated with lost circulation can severely impact drilling operations. The negative consequences are magnified greatly in the deepwater environment. Dramatic reduction in penetration rate and the downtime spent regaining circulation can further escalate already high operating costs. More importantly, the well control issues surrounding lost circulation pose critical safety concerns.

In many of these wells, merely identifying the thief zone or zones is a major technical challenge. Furthermore, once identified, the vugs and fractures in the loss zones are at times too large to be bridged with conventional lost circulation material. This paper describes the development of a uniquely engineered lost circulation pill that when used in tandem with new real-time geomechanical analysis methods and pill formulation software, cured severe losses in the deepwater Gulf of Mexico.

The authors will describe the development and laboratory modeling used in producing the specialized and chemically activated cross-linked pills, engineered to stop whole drilling fluid losses. As detailed in the paper, the pill proved to be far superior to conventional lost circulation material. Further, the paper will discuss its application in a well drilled in more than 2,800 ft of water in the Gulf of Mexico, which had encountered losses of up to 2,000 bbl of synthetic-base drilling fluid. The 100-bbl pill was formulated using a specialized software package. This was used in combination with a new process for analyzing the location, and extension pressure of the drilling induced hydraulic fracture using resistivity and annular pressure measurements. Once the pill was placed across the fracture zones, squeezed and later drilled out, normal drilling resumed with pre-fracture parameters resulting in penetration rates in excess of 50 ft/hr with no further losses.

In addition to discussing the development and application, the authors will outline the lessons learned on the deepwater project featuring pre-planning issues geared toward ensuring circulation is maintained throughout the wellbore.
Reservoir Limit Testing For Fractured Wells
Authors: Gringarten Alain C.
Published: December 2007

The purpose of the paper is to extend reservoir limit test analysis techniques to fractured wells. By deriving the pseudo-steady state pressure functions for an unfractured and a fractured well at any position of a closed rectangle, it is shown that shape factors for fractured wells are not readily obtainable from the ones for unfractured wells.

Exact analytical expressions of shape factors for fractured and unfractured wells in a closed rectangle are presented, along with graphs of these quantities versus appropriate parameters.

Type curves for a fractured well at the center of a closed rectangle are also provided. Both uniform flux and infinite conductivity fractures are considered.

The curves presented in this paper are then used with actual field data for estimating the drainage volume of a fractured well and the shape of the well drainage area.

INTRODUCTION

Reservoir limit tests, introduced by Jones1, are commonly used for evaluating the reservoir volume communicating with the well. The analysis is based on the fact that the well pressure during pseudo-steady state flow is a linear function of the production time:Equation 1

whereEquation 2

andEquation 3

A represents the drainage area (in sq.ft) and CA the drainage area shape factor. Eq. 1 may also written in dimensionless form as:Equation 4

withEquation 5

andEquation 6

A cartesian plot of bottom-hole flowing pressure versus production time will thus yield a straight line after pseudo-steady state conditions are reached. The slope of the straight line (Eq.2) may be used to estimate the connected reservoir drainage volume:Equation 7

and the drainage area, if Ï?h is known.

The shape of the drainage area may be estimated from the pseudo-steady state cartesian plot if pressure data are also available from an infinite acting flow period2. These are used to determine the semi-log straight line slope:Equation 8

and p1hr. The system shape factor is then obtained from:Equation 9

By comparing the calculated CA with the ones published in the literature for various drainage area configuration3–5, it is possible to estimate the shape of the drainage area.
Systematic Team Approach to Drilling Optimization Reduces Well Construction Time by 15%, Ghadames Basin, Algeria
Authors: Devine Les , Ellins Martin , Scotchman Alasdair , May Norman , Connell Sean
Published: December 2007

Drilling through highly inter-bedded Tertiary to Devonian age formations in the Menzel Lejmat Field, Algeria presents a number of distinctive challenges. Problematic overburden consists of abrasive sands, inter-bedded evaporite/carbonate sections, inter-bedded sand/claystone formations in addition to a 30-meter band of extremely hard dolomite. Rock strengths vary greatly with sonic transit times ranging between 55 to 140 milliseconds. Recently, Burlington Resources identified a need to improve drilling efficiency through these problematic formations. They contracted a drilling optimization service (Baker Hughes OASIS) to perform a detailed performance study of offset wells in order to plan and implement a more efficient drilling program for well (MLC-2). The objective was to increase penetration rates, preserve borehole stability, reduce the number of bits and lower overall drilling costs.

After analyzing offset wells to benchmark current performance, the service team developed an optimization plan that outlined key areas for improvement. This study included depth based drilling data, wireline log data and daily drilling reports from offset wells. This information was analyzed and a report generated that included projected lithology and mechanical rock properties as well as potential drillability problems. The team recommended specific bits, BHAs and operating practices to address these problems. A summary report of each hole section was provided for use at the rig site to ensure planned goals and targets were achieved. The report outlined depths at which potential problems could occur and what operating practices should be followed to eliminate or to minimize their severity.

The drilling of MLC-2 was a significant success. The 12-1/4" hole section was drilled with one bit for the first time and hole quality was greatly improved. The well was drilled six days ahead of the AFE curve and five days ahead of the best performing offset. This represents a 15% reduction in well time saving approximately $300,000. A detailed post-well analysis was performed to document performance achieved and to carry the numerous lessons learned forward.

Additionally, subsequent wells were analyzed in a similar manner with special attention given to the 12-1/4" and 6" hole sections. Performance improvement on these wells demonstrated that a continuous improvement process allied with a Polycrystalline Diamond Compact (PDC) development initiative, ensured bit design was optimized for rate of penetration (ROP) and length of run. The authors will document penetration rate and run length records achieved using this process. This paper will also describe process improvements and how lessons learned were fed back into the continuous improvement process to build momentum.
Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid
Authors: Saasen Arild , Jordal Ole Henrik , Burkhead David , Berg Per Cato , Løklingholm Geir , Pedersen Erik Sandtorv , Turner Jim , Harris Michael J.
Published: December 2007

During the drilling and completion of the Huldra field in the North Sea, high temperature and high pressure conditions were expected and encountered in the reservoir section. The difference between the pore pressure and the fracturing pressure is small. Cesium formate had been evaluated as a potential drilling and completion fluid, but technical hurdles could not be completely addressed in time for the first well. As a result of well control problems occurring in the first well, with barite sag in the oil based drilling fluid as a contributing factor, it was necessary to use a drilling fluid with insignificant potential for sag. For the first time worldwide the cesium formate brine was chosen as a drilling fluid. This fluid could be delivered solids free with densities up to 2.2 s.g. The required down hole density in the well was 1.91 s.g. At the same time it was necessary to have as little contribution to the equivalent circulating density (ECD) from the flow as possible.

The paper describes how the cesium formate brine was used successfully as a drilling and completion fluid. The effect of the fluid on well control, hole cleaning, rate of penetration (ROP), torque/friction, ECD, formation damage, casing wear and hole stability are covered. The paper also describes actions required to minimize losses of this very expensive fluid. The challenges acquiring adequate formations logs while drilling are also described. Finally, the use of cesium formate brine during the completing of the wells with open hole sand screens is outlined.
Analysis of the Fatigue Resistance of Rotary Shouldered Connections
Authors: Collins Tony , Vaghi Francesco
Published: December 2007

It is widely accepted that understanding of the stresses, and thus fatigue resistance, of rotary shouldered connections requires numerical stress analysis, and that the contact between box and pin threads makes this a complex problem. Previous analyseshave usually dealt with one particular connection, and have varied in their approach to the spiral nature of the thread.

This paper covers a range of connections from NC38 to 75/8 H90, and uses multiple cases at different rotations to allow an axisymmetric model to simulate a spiral thread. The effects of alternating stress and make-up are separated, and then combined using a Gerber plot to predict relative fatigue resistance of various connection geometries. These results are consistent across connection styles, which makes it unlikely that they are due to modeling anomalies.

Conclusions are drawn as to the beneficial effects of stress relief grooves, and on the significance of the geometry of the standard groove. The results can be used with simple beam-theory analysis to make useful strength predictions, and allow the evaluation of the effects of modifications to standard connections to meet the needs of drilling and measurement tools.
New Buckling Solutions for Extended Reach Wells
Authors: Mitchell R. F.
Published: December 2007

New exact buckling solutions have been found for horizontal wells. These solutions include critical axial buckling force, a variable pitch depending on pipe lateral weight, length change due to buckling, pipe wellbore contact force, and pipe bending moment. Previously, these results could only be obtained with non-linear computer solutions. Applications of these results include estimating lock-up conditions, determining loads that could cause permanent corkscrewing, and determining seal lengths for horizontal well completions. Several sample calculations are presented which illustrate the use of these new results to solve practical engineering problems.
Coiled Tubing Risers: Are They Stiff Enough?
Authors: Crabtree A. , Meadowcroft W.
Published: December 2007

The trend over the last few years in Coiled Tubing (CT) usage has been towards a greater preponderance of large diameter, heavier wall section and higher yield strength tubing being employed. These larger, stronger section tubing strings require larger forces to be applied than those previously experienced in the industry, in order to reel and unreel the pipe from the working reel or spooler. These forces are transmitted to the riser on which the CT injector and guide arch are mounted. In turn, the toolstrings which are now more commonly used in well intervention operations are longer, requiring longer risers to accommodate them. This causes higher loads to be imposed upon the wellhead on which the riser is mounted. The wellhead, or Christmas Tree, is the primary well containment on which other well control equipment, such as Blow Out Preventers (BOP), are attached. Does this change in operating parameters now mean that the Christmas Tree is being overloaded to the point of a potential breach in its integrity?

The advent of longer risers, which are subjected to greater loads from more powerful high pull capacity injectors and more powerful reels, gives concern as to whether or not the types of riser commonly assembled in the field are stable or liable to suffer catastrophic buckling collapse. This is not readily apparent, as the types of risers being used are composed of diverse structural elements; multiple BOP’s, API flanged spools, Pin & Collar quick union riser sections, flow tees, et cetera.

This paper will present a summary of an engineering study that was undertaken to explore these questions. The study examined the effect on stability imposed by riser internal pressure, riser configuration, pipe loads and support tie-downs, as well as the loads that are being transmitted to the Christmas Tree. The study was undertaken using both existing engineering principles and Finite Element Analysis (FEA). The result of the study was the development a formulaic model, to be used within a computer simulation program, that would account for these varied inputs.
Well Intervention Outside of Short String Experiences in Java Sea - Indonesia
Authors: Hendra Yasri S. , Wibowo Wahju , Yoliandri Susilo , Rich David
Published: December 2007

Performing coiled tubing and wireline well interventions outside of the short string in dual completions has become an acceptable part of well intervention activities in the Offshore West Java field over the last 2 years. Previously, most well intervention activities below the end of the short string tubing were avoided due to the perceived high risk of problems such as getting stuck by wrapping tools around the long string or wedged between the long string and the casing wall.

West Java is a mature field with almost all the wells penetrating multi-layer reservoirs. Reservoir management issues have resulted in a large number of dual completions. In order for wells to maintain production at their potential rates and for the shut-in wells to be reactivated, well intervention activities need to be performed regularly in both strings. To date, 14 coiled tubing interventions outside of short string have been completed. Coiled tubing intervention consists of 8 fill clean outs, 2 cementing jobs, 1 fishing job, 1 polymer water shut-off and 2 stimulation jobs. Perforation jobs were done after performing coiled tubing cementing and water shut off jobs. All these jobs have been done with a high degree of success under a varity of well conditions (high angle, etc).

This paper will explain several problems that were encountered while working outside of short string, especially during coiled tubing interventions. Several ideas have been applied and lessons learned to overcome these problems. If we look back at the results in the Offshore West Java field over the last two years, working outside of short string has become a common practice in sustaining or even increasing production and in re-activating shut in wells.
Operational Issues Related to 120Ksi YS Tubing
Authors: Andersen J. N. , Rosine R. S. , Martin John , Deshotels Steve
Published: December 2007

As the coiled-tubing industry develops and begins to use higher-grade tubing materials, several special considerations must be addressed for safer operations. Tubing material properties have reached 120Ksi yield strength (YS). This paper will address some special considerations for safely operating with higher-grade material, including proveup of the tubing material, surface equipment issues, and BOP considerations. Several tests concerning these issues have been conducted to verify proper operating conditions and equipment.
A Comparison of Mud Pulse and E-Line Telemetry in Alaska CTD Operations
Authors: Ohlinger James J. , Gantt Lamar L. , McCarty Thomas M.
Published: December 2007

Coiled Tubing Drilling (CTD) has been used on the North Slope of Alaska to drill in excess of 250 re-entry sidetrack wells since 1994. Most of the through tubing coil sidetracks were drilled with a conventional bottom hole assembly (BHA) consisting of a mud pulse MWD tool, and a mechanical/hydraulic orienter. Recently fifteen CTD sidetracks were drilled in Alaska using a BHA that communicates to and from the surface via an electric line in the coil.

Both the conventional mud pulse telemetry system and electric line BHA are described in this paper. However, the primary goal of this paper is to compare the actual performance of the electric line BHA to the conventional mud pulse tools. In addition to drilling rate, several other drilling parameters will be discussed. Time spent surveying, logging, drilling time, orienting, and BHA handling will be addressed. (Fig. 1)