bluuebunny/crossref_metadata_2025_split huggingface dataset:
System for Drilling an Offshore Shallow Sour Gas Carbonate Reservoir
Authors: Quitzau R. , Brand P. R. , Tarr B. A. , Frink P. J. , Leuchtenberg C. 
Published: December 2007

Abstract
Special practices and equipment were used to safely and efficiently drill 9 development wells in the sour NSO A Field offshore Indonesia. The objective carbonate reef zone has been notorious for severe lost circulation followed by gas kicks during drilling operations. In the past, rig crews attempted to cure the lost circulation before drilling ahead. This resulted in excessive time and safety risks. Using the system described in this paper, safety was improved and the time to drill the carbonate reservoir was reduced from an average of 16 days per well down to 5 days per well.
A rotating blowout preventer (RBOP) was used to blind drill by pumping seawater simultaneously down both drillstring and annulus. The RBOP allowed surface pressure to be applied on the annulus while drilling and thus enabled the use of cheap seawater rather than expensive mud to hydrostatically overbalance the well.
A special gas handling system was installed to safely burn sour gas. Rig crews were trained to handle the gas and evacuate the rig if necessary. Sour gas was burned at surface on 2 occasions during the project. Eventually, the success of the blind drilling practices enabled the crews to avoid bringing any gas to surface during drilling.
Of nine wells drilled, six wells encountered severe lost circulation. Seawater was injected into these wells to keep the sour gas in the reservoir while drilling or tripping. On 4 of these wells, blind drilling practices were used to reach total depth. Diesel oil - bentonite - water plugs were set in the bottom section of intermediate casing to stabilize the well prior to running pre-perforated production liners with drill-in capability.
Field Data Supports the Use of Stiffness and Tortuosity in Solving Complex Well Design Problems
Authors: Rezmer-Cooper Iain , Chau Minh , Hendricks Andy , Woodfine Miriam , Stacey Brian , Downton Neil 
Published: December 2007

Abstract
Torque and drag analysis has been used for more than ten years to drill wells ‘on paper’. Representations of the drillstring and bottomhole assembly (BHA) that do not include the individual component stiffness have been used with some success in analyzing and preventing problems in extended reach drilling. As curve rates have increased in directional wells and the trajectories themselves become more complex, the effects of the previously neglected stiffness have led to errors in the sideforce calculations that underpin all torque and drag analysis. Finite-element analysis can solve this problem. Additionally, tortuosity can be added to provide a rippled effect to a well trajectory design that simulates the micro dog-legs that occur in the drilled well, enabling more realistic bounds to be placed on the drag and torque losses, and the forces experienced by the drillstring. Tortuosity also allows more accurate modeling of the side forces between the casing and drillpipe, critical to extended reach well design. This is illustrated using a well with a deep kick-off point from the Gulf of Mexico.
A case study based on wells drilled from the Hibernia platform is used to illustrate how the model has been utilized to aid planning decisions and reduce costs.
Underbalanced Drilling in a Depleted Gasfield Onshore UK with Coiled Tubing and Stable Foam
Authors: Nas S. 
Published: December 2007

Abstract
Drilling a sidetrack into a severely depleted gas reservoir is a challenge that can be safely completed using underbalanced drilling technology. Smedvig Offshore completed a sidetrack in a depleted gas reservoir onshore using a rig and a coiled tubing drilling system. A short planning time, a lack of available equipment combined with a restricted operating window and a low budget made this well a challenging project.
Coiled tubing drilling has matured over recent years and the coiled tubing drilling experience gained by Transocean combined with the underbalanced drilling experience gained by Smedvig in the southern North Sea helped to bring this well to a successful conclusion.
The operator is a small independend UK company and required a cost effective solution to this project. The operator intends to convert the field to a gas storage reservoir and to obtain the required injection and production rates wanted to drill a 1000ft horizontal section with a minimum 6" hole size. The reservoir pressure at 1450ft was 240 psi.
The original well was abandoned and sidetracked with a rig. After running and cementing the 7" liner a coiled tubing unit was used to drill the reservoir underbalanced.
Using a stable foam system an annular pressure of 30 psi was obtained. Once gas production started the well was choked back to limit the inflow. Both production and ROP improvement was significant and TD was called after only 750ft of reservoir was drilled because of production rates. The well was completed open hole to ensure maximum hole diameter. No hole collapse or sand production has been encountered.
Planning an Effective Aerated Drilling Operation in Hard Formation Based on Cost Analysis
Authors: Negrão Alvaro Felippe , Duarte Nilo Azevedo 
Published: December 2007

Abstract
The use of air/mist/foam drilling has been increasing over the years bringing advantages not found in conventional drilling. The comparison between the performance of conventional and two-phase flow drilling has shown the second technique presents several advantages to the last one1: (1) minimum or no damage to sensitive pay zones, (2) immediate and continuous evaluation of cuttings for hydrocarbon shows, (3) avoidance of lost circulation, and (4) higher penetration rates in hard formations. Advantages of air/mist/foam drilling regarding penetration rate in hard formation have been pointed out in previous technical papers. Few questions remain regarding the improvement in penetration rate when using this technique. However, questions arise when the main topic is savings attributed to two-phase flow drilling operations. The answers for those questions are not easy because many of the economical factors involved depend on each particular case. There are situations, mainly in wild cat wells, where the operator may not have all necessary input data for choosing the best option between an aerated or conventional drilling technique. Some data are within the direct control of the operator. Others, however, are beyond its influence and control, like the geological uncertainty and equipment performance. The necessary data for an appropriate cost analysis of an aerated operation includes the spread daily rate of drilling rig, the air drilling equipment day rate, the air equipment diesel supply, the air equipment rig up and rig down time, the hard formation thickness, and the expected penetration rate.
This paper focuses on the economics and operational results of using a two-phase flow drilling technique. The intent of this text is to demonstrate how, when, and why an oil company should implement an air/mist/foam operation in hard formation to accomplish the expected economical results. It describes an analysis performed for a wildcat well in Colombia, Los Mangos 60, using all the previous cited necessary data. In that location there were uncertainties related to hard formation thickness and expected penetration rate, so a cost analysis was performed to support a decision about the drilling technique to be used. The analysis used equations and graphs to represent almost all the involved costs, giving support for an appropriate decision. The paper also presents field results collected during the aerated drilling operation, showing that the decision to use this technique was the most appropriate.
Quantifying Bottomhole Assembly Tendency Using Field Directional Drilling Data and a Finite Element Model
Authors: Lesso W. G. , Chau M. T. , Lesso W. G. 
Published: December 2007

Abstract
Predicting the directional tendency of a bottomhole assembly (BHA) is a key element in improving the efficiency of the directional drilling process. Finite element models attempt to represent the detailed physical interactions between the BHA and wellbore while drilling. However, effective use of such models has been hindered by parameters that are difficult to quantify, particularly the strength of the formation and variations in hole gauge.
Details of over 6400 BHA runs made in the Gulf of Mexico from 1994 through 1997 were used in a systematic statistical analysis and combined with intelligent use of the tendency models to yield information that is not readily apparent in single runs of the software. This information can then be used as a predictive tool to minimize the effects of the parameter uncertainties, and to isolate and calibrate those variables to which the models are sensitive. From these studies the most representative values for formation stiffness and hole over-gauge were obtained for various areas within the Gulf region.
We describe a methodology using this combination of advanced modeling and statistical analysis to provide more reliable predictions of BHA tendency and to give an indication of the conditions where such predictive techniques can be effectively applied.
On-Line Torque & Drag: A Real-Time Drilling Performance Optimization Tool
Authors: Reiber Frank , Vos Bart E. , Eide Svein E. 
Published: December 2007

Abstract
A technique for evaluating torque and drag effects in real time and for interpreting the effectiveness of actions taken is presented in this paper. The application determines total wellbore and incremental hole sections friction factors real time using downhole measured weight on bit and bit torque data coupled with surface load measurements or just surface data. In addition the system determines buckling modes, minimum yield and fatigue safety factors. The application enables field personnel to identify drilling performance problems as early as possible.
This paper presents the algorithms and calculation procedures used as well as several case histories from wells drilled offshore Norway, offshore Denmark and onshore Germany.
The Buckling Behavior of Pipes and Its Influence on the Axial Force Transfer in Directional Wells
Authors: Kuru E. , Martinez A. , Miska S. , Qiu W. 
Published: December 2007

Abstract
An experimental set-up was built at the University of Tulsa to study buckling and post-buckling behavior of pipes constrained in a straight horizontal and curved wellbores. Experiments were conducted to investigate the axial force transfer with and without static internal pressure. Different stages of buckling phenomena and their relation to the axial force, the pipe diameter (1/4" and 3/8") and the pipe endsupport conditions have also been investigated. Experimental results have shown that the buckling load is a strong function of the pipe diameter and the pipe end-support conditions. Static internal pressure appears to have insignificant influence on the buckling behavior of pipes.
A brief review of recently developed mathematical models to predict buckling behavior of pipes in inclined, curved and horizontal sections of wellbore is also presented. Applications of the current theory are presented by using recently developed computer simulator. Results of the theoretical analysis have confirmed the versatility and effectiveness of computer simulator for better understanding and solving buckling related problems in the field.
How to Design Rock BitsTo Drill Ultraabrasive Quartzitic Sandstone in Horizontal Wells, Algeria.
Authors: Besson A. , Rabourdin J. L. , Huon W. , Cazenave F. 
Published: December 2007

Abstract
Drilling a long horizontal section within an ultra abrasive formation means short bit runs and high drilling costs. Despite many trials with standard technology bits in this gas reservoir in Algeria, the drilling performances were so poor that the profitability of the development project was greatly reduced.
This paper describes the process to achieve the development of a specific bit design which eventually greatly improved the drilling performance in ultra abrasive sandstone formation and reduced the number of bits used.
The problem analysis was based upon the evaluation of the bit performance history in combination with a full description of the physical characteristics of the rock. The abrasiveness of the sandstone was clearly the main factor which reduced the bit life, particularly in horizontal drilling. In order to increase the run length, the first objective was to reduce as much as possible the frictions of the bit cutting structure against the formation as well as to protect the bit gauge and heel.
The analysis of the rock structure allowed to determine that despite its high abrasiveness, the sandstone presented a hardness weaker than expected. Therefore the penetration rate could be improved with a bit design aimed at favoring the crushing action.
After developping two different bit designs and drilling three wells the rate of penetration and the footage were more than tripled. This is the result of a team work between the bit manufacturers and the operator.
Dual Torque Concept Enhances PDC Bit Efficiency in Directional and Horizontal Drilling Programs
Authors: Mensa-Wilmot Graham , Krepp Tony , Stephen Ita 
Published: December 2007

Abstract
The emergence of PDC bits as viable drilling tools has helped improve operational efficiency in various drilling programs. This is especially true in conventional or vertical hole drilling, where improvements in the application of PDC bits, and their technology1 continue to re-define the known limits of these bits.
However, in directional and horizontal drilling programs, industry acceptance of PDC bits has been "lukewarm", due to a lack of consistent performance in today's environments. As well designs become more intricate - deeper targets, extended reaches and increasing well profile complexities - it is evident that tomorrow's challenges will require new technologies2, 3.
This paper describes a new concept in PDC bit development for directional and horizontal drilling programs. The concept establishes a "dual torque" response, which enhances operational efficiency in both the sliding and rotating modes of deviated hole drilling. Three parameters - sliding slope, rotating slope and transition weight - govern the dual torque behavior. In addition, two sets of parameters – performance requirements and performance objectives4– that define PDC bit efficiency will be discussed.
The paper will establish the relationships between the dual torque concept's parameters, as they relate to tomorrow's directional, horizontal and extended reach drilling challenges. It will show how the concept determines different performance qualifiers in terms of well profile complexities, and operational environments. Analytical and laboratory data, as well as field examples showing the concept's effectiveness and consistency for different deviated drilling programs will also be presented.
Probabilistic Reserves! Here at Last?
Authors: Capen E. C. 
Published: December 2007

Summary
Recently, the SPE and WPC modified earlier definitions of reserves for the industry. Through much lobbying about improving the definitions more, the committees pretty much held on to the past.
Many hold the belief that for the first time the definitions allow for the use of probabilistic reserves though they do not require this methodology. Not true. Reserves estimates have always been probabilistic whether or not the definition recognized that fact. The weasel words chosen such as reasonably certain, with high confidence, more likely than not, and possible all lay tribute to the concept of probability. These words and phrases by design take the place of numerical probabilities so that estimators would not have to actually use the mathematics of probability and statistics. On the other hand, the use of the word "proved" suggests that to some, probability was not such a big deal. When remaining proved reserves can increase by factors of 10 or more over a few year period, we must admit that the uncertainties associated with reserve estimates are not so trivial after all.
One particularly sticky problem in the past was how to combine well reserves estimates to get reservoir reserves or field reserves—not that most people recognized this as a problem. People simply added them together as intuition would dictate. Incorrect. Ending up with less than proved reserves, by definition, constitutes a rare event. There has to be little chance that the field would be any smaller.
The sum of 5 rare events (proved reserves from 5 wells) is much more rare than any one of the contributing elements. So what started out as reasonably certain becomes extremely certain. This latter phrase no longer fits the definition of proved. With this error promulgating throughout districts, regions, companies, and the world, we end up with nonsensical numbers. Whatever methodology one uses, he must both start and end up with something about which he feels reasonable certain. Probabilistic methods provide easy solutions.
First, estimators must recognize that the Central Limit Theorem works overtime in our industry. It ensurs that the distribution of remaining reserves is always lognormal and includes provision for probable and possible reserves. Time to quit debating this issue. Second, having created a lognormal distribution for zones, wells, or whatever building block they use, they can combine them into reservoirs, fields, and company reserves. The mean of the sums is the sum of the means always, and most always, the variance of the sum is the sum of the variances. The effort need not require the labor of Monte Carlo Analyses. A spreadsheet analysis does-it quickly.
Choosing probabilistic methods gives us the possibility of reporting more proved reserves. The deterministic method biases the results to the low side. Using probabilities, a company's proved reserves could increase by 25% to 50%.
Utilizing Discounted Government Take Analysis for Comparison of International Oil and Gas E&P Fiscal Regimes
Authors: Rapp William J. , Litvak Boris L. , Kokolis George P. , Wang Ben 
Published: December 2007

Abstract
The concept of fiGovernment Takefl is often used to compare International Exploration and Production (E&P) fiscal regimes for potential investments in oil and gas projects. fiGovernment Takefl is commonly defined as the percentage of all payments to Governments, over the life of a project, as a portion of the cash flows that remain after all project capital investment and operating costs have been paid. Examples of payments to Governments are: income taxes, royalties, profit petroleum share, bonus payments, value-added taxes, excise taxes, excess profits taxes, remittance taxes, state oil company carries, import duties, etc.
Virtually all Oil and Gas Companies use discounted cash flow analysis in project decision making. Likewise, when utilizing the concept of fi Government Take fi in comparing projects in different fiscal regimes, it is important to consider the opportunity cost of capital as it applies to the payments made to Governments, as well as the project™s revenues and costs. Since the timing of payments to Governments can vary widely depending on the structure of fiscal regimes, it is important to include the effect of this timing in the calculation of fiContractor Takefl. Payments to Governments can occur at the front end of a project (i.e. front-end loaded); for example-signature bonuses, import duties or value-added taxes, or they can occur later in a project™s life, such as is usually the case with profit Œ based taxes. If this variability of timing of the payments to Governments is not considered, two identical projects which are in different fiscal regimes may have identical Government Takes over the life of the projects, and yet the present values of those payments, discounted at an appropriate opportunity cost-of-capital, may be very different.
In order to avoid these potential distortions in comparison, it is suggested to utilize the concept of fiDiscounted Government Takefl to compare different international E&P fiscal regimes.
This paper will illustrate the utility of this concept by comparing the economics of several generic E&P projects in different International Oil and Gas E&P fiscal regimes based on fiGovernment Takefl and fiDiscounted Government Takefl. It will be shown that there can be significant differences between fi Discounted Government Takefl and fiGovernment Takefl, and that as a result, the relative attractiveness of countries™ fiscal regimes can be quite different when ranked based on using the more economically sound fi Discounted Government Takefl than when comparison is made on fi Government Takefl.
In addition, it will be shown that the difference between Government Take and Discounted Government Take can be used to measure the degree of front-end loading of Government Take.
Artificial Neural Network Enhanced Completions Improve Well Economics
Authors: Shelley Robert F. , Grieser William V. 
Published: December 2007

Abstract
Evaluating and optimizing well-completion procedures can be difficult because of a lack of understanding about the reservoir and completion dynamics. In many cases, a well completion is a compromise between optimum reservoir, well, completion, and operational factors. In this paper, we discuss the use of a form of artificial intelligence, the Artificial Neural Network (ANN), as a tool to enhance our ability to improve well economics. ANN models trained on reservoir, well, and completion information can predict well cumulative production with an acceptable degree of accuracy (less than 15% average absolute error).1–4 Sensitivity studies of these networks show that for a given reservoir quality, the completion method can significantly affect the well's production outcome. Case histories are presented in which an ANN sensitivity analysis was used to justify changes in completion/stimulation procedure. These ANN-enhanced completions resulted in improved well economics compared to the standard completion-optimization methods normally used in these fields.
This paper presents case histories in which ANN helped establish well completion priorities that improved well economics. ANN technology has been used in areas where a well-completion experience base exists. The completions analyzed with ANN techniques include the Red Fork formation in Roger Mills and Custer counties in Oklahoma; the Frontier formation in Lincoln County, Wyoming; and the Granite Wash formation in Roberts County, Texas. Specific areas of interest include any quantifiable well, reservoir, or completion characteristic that affects well production (porosity, thickness, pressure, geology parameters, well characteristics, completion/stimulation procedures, etc.). Net present value (NPV) was used for quantifying the economic effect of ANN enhancement on well-completion economics.