bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Optimization Using Bit Selection Expert System and ROP Prediction Algorithm Improves Drilling Performance and Enhances Operational Decision Making by Reducing Performance Uncertainties
Authors: Bjornsson E. , Hucik B. , Szutiak G. , Brown L. A. , Evans H. , Curry D. , Perry P. 
Published: December 2007

Abstract
A rule based drill bit selection expert software system and Rate of Penetration (ROP) prediction algorithm has been recently applied in the optimization process of a 4500 m vertical foothills well in Western Canada. Post well analysis shows that when the expert system recommendations were followed by the operator, increases in ROP and run length over the local pacesetter well were experienced in each hole section. ROP increases of 15% in the 311.1mm section, 52% in the 215.9mm section and 60% in the 142.9mm section were achieved, as well as bit life increases up to 33% with TCI bits. Although the operator did not follow all of the expert system recommendations through the entire well, these increases did contribute to savings in drilling time below AFE of 15 days over the entire well. Comparison with the actual drilling performance showed close agreement in trend to the predicted ROP through most lithological intervals, which helped to confirm the accuracy of the process of geological / pore pressure predictions and the ROP prediction algorithm.
The expert system is a rule based bit selection system that uses a detailed description of the drilling environment, including meter based lithology, synthetic wireline logs, predicted pore pressures and anticipated operating parameters of the well or hole interval being analyzed to produce a bit selection recommendation including IADC bit type and bit features. The ROP algorithm has been developed as a drilling optimization tool and attempts to model the technical limit ROP that can be expected through a given hole interval. The ROP algorithm uses as its inputs detailed lithological descriptions of the anticipated formations, hole size, mud weight, predicted pore pressure, bit type, and anticipated operating parameters to calculate an accurate meter based ROP prediction. The ROP algorithm has been applied in several drilling environments worldwide and comparisons with actual drilling performance have been used to modify the calculations and improve predictions.
The ROP algorithm improves drilling decisions, and provides performance analysis while guiding financial planning. The ROP algorithm can be applied in the planning phase of a project to develop time curves based on expected performance and to compare and contrast potential bit/BHA types based on performance predictions. Furthermore, the ROP algorithm can be used in post-well analysis to identify areas where potential drilling performance was not achieved, and help in identifying improvements for future projects.
Reducing Well Cost by Gravel Packing in Nonaqueous Fluid
Authors: Hecker Michael T. , Barry Michael D. , Martin Thomas B. 
Published: December 2007

Abstract
As operators continue to develop prospects in expensive, deep water environments, delivery of high rate, high capacity, long life wells become essential for economic success. Often, operators are drilling high angle, open hole wells to maximize production by capturing reserves from several sand packages in one wellbore. In many of today's deepwater applications, hole stability and shale inhibition are keys to a successful open hole completion. Nonaqueous fluid (NAF) is the preferred fluid system to optimize drilling of the open hole section, but hole stability can be problematic during displacement operations prior to gravel packing. This paper describes a gravel packing technique that allows the operator to run the gravel pack screens in NAF, gravel pack the well and displace the casing to brine, all in one trip. Running the screens in NAF significantly increases the probability of successful screen installation and the end result is consistent, cost effective delivery of high rate, low skin completions.
Monobore Completion Using Interventionless Technology in Offshore Horizontal Gas-Injection Wells
Authors: Etuhoko Michael O. , Lewis Proctor 
Published: December 2007

Abstract
The Amenam/Kpono field is located eastern offshore of Nigeria in a water depth of 43m and about 35km away from the coast. The field development has been challenging in so many ways: Deep reservoir targets (3600m to 4300m TVD/SL)High temperatures (130 -150 degree Celsius)High pressures (370 to 500 bar)High- reach departures up to 3km in certain wellbores, giving rise to highly deviated and deep wells (up to 6600m MD/RT)Reservoir fluid containing 3% by weight paraffinReservoir fluid containing 3% carbon dioxide contentCritical reservoir fluids (bubble point pressure is very close to the reservoir pressure in the main reservoir). This necessitates the requirement for the early and efficient pressure support for the reservoir
In order to deliver wells under the above challenging environment and circumstances such as to ensure field life production, a lot of emphasis is placed on completions optimization. Hence, completion technology was taken beyond the conventional limit and an innovative, reliable and cost effective approach applied through complete integration of the service companies.
The main interest was to reduce the operational risks with diverse and enhanced completion equipment in order to reach the plateau as quickly as possible. Hence, a Monobore completion design with Interventionless technology was embraced in this offshore field development. The total budget for the first phase of the development is $1.5 billion (U.S.) and it covers drilling, completion, construction and production installations.
This paper will discuss the well completion designs, material selection, manufacturing, preparation, execution and evaluation of the Amenam/Kpono well completion. The paper will focus more on how new technologies (Reservoir drilling fluid, fluid spring-operated valve, gravel-pack packer, tubing-tester flapper valve, production packer, permanent gauge, etc) are integrated in all the wells, and especially, in the challenging horizontal gas injectors.
By using these technologies, completion efficiency was increased, safety performance was improved, and rig cost was reduced by 50 hours per well.
Trinidad and Tobago's Deepwater Drilling Saga
Authors: Rajnauth Jerome , Boodoo Craig 
Published: December 2007

Abstract
Trinidad and Tobago is endowed with abundant oil and gas reserves both onshore and offshore. Most of the reserves offshore have been found in the shallow water shelf area. Over the last couple of years exploring the deep waters beyond the shelf (&gt;1000 meters) has been looked at with much anticipation. However, the eight (8) wells drilled thus far have not found hydrocarbons in commercial quantities. It is important to note however, that many geo-scientists believe the exploration work in the deepwater proved the existence of a working hydrocarbon system.
The drilling phase of the exploration activities in the deepwater blocks (i.e Blocks 25(a), 25(b), 26 and 27) produced many challenges. This paper will look at the major problems, risks and uncertainties encountered during the drilling of these wells and highlight key learnings that would be useful for further drilling in the deep and ultra deep waters off Trinidad and Tobago. The major well objectives will be perused to determine if these were actually attained.
Results showed that some of the wells were unable to reach their technical objectives. As a result the actual number of days and cost for some wells were less than originally planned.
Solid Expandable Tubular Technology: The Value of Planned Installation vs. Contingency
Authors: Rivenbark Mark , Demong Karl , Mulhem Sami S. , Olivera Glen 
Published: December 2007

Abstract
From deepwater exploration to onshore producing wells, solid expandable tubular technology can provide substantial savings in total well cost. Operators considering new options in well design have discovered the potential and practicality of these expandable systems. Land wells are being planned using the technology to slim wellbore design. Offshore wells have coupled the slimming well-design concept with a surface stack to enhance the drilling process.
Limitations associated with using a surface stack frequently result in well depth targets being missed. Solid expandable tubular technology provides casing design alternatives that allow access to these previously out-of-reach targets. Simply put, employing expandable technology in the surface stack process allows wells to be drilled deeper at less cost.
Early deepwater surface stack technology was limited to a four-casing string well design (13-3/8 in., 11-3/4 in., 9-5/8 in., and 7 in.). Shallower reservoirs proved to be within reach of this four-string well design, prompting identification of prospects in deeper reservoirs. These subsequent reservoirs pushed the targets to depths unreachable using the conventional four-string well design. Solid expandable tubular systems provided the technology to reach the targets by incorporating two additional casing strings (9-5/8 × 11-3/4 in. and 7-5/8 in. × 9-3/8 in.) while still maintaining hole size. Deepwater surface stack technology is evolving to a five-casing string conventional well design capability (16 in., 13-3/8 in., 11-3/4 in., 9-5/8 in. and 7 in.) with the option of incorporating three solid expandable tubular strings (13-3/8 × 16 in., 9-5/8 × 11-3/4 in., and 7-5/8 × 9-3/8 in.). Drilling wells using solid expandable tubulars with a surface stack translates into savings in wellheads and risers, mud, cement, and cuttings removal.
Solid expandable tubulars are proving to be just as adaptable and cost efficient in land well construction. Onshore wells with four-string casing designs are being slimmed so that an entire 7,000 ft well can be drilled with no hole section larger than 12-1/4 in., eliminating traditional 22 or 17-1/2 in. hole sizes. The smaller hole also increases the rate of penetration (ROP)
This paper will discuss the unique challenges of casing systems associated with both deepwater and onshore exploration. The process of identifying, planning, and executing the integration of solid expandable tubulars with surface stack drilling will be analyzed and evaluated. Diverse case histories will illustrate how these technologies can overcome the limitations of conventional technology, and do so in a cost-effective way.
Transition Time of Cement Slurries, Definitions and Misconceptions, Related to Annular Fluid Migration
Authors: Rogers Murray J. , Dillenbeck Robert L. , Eid Ramy N. 
Published: December 2007

Abstract
Transition time of cement slurries is a term that has been used throughout the oil industry for many years. During this time, the term has been defined, redefined and misused to cover a wide range of cementing topics. This has led to numerous misconceptions and confusion as to what transition time really means. For many years, this term has been directly tied to the term right-angle-set, which relates to the speed in which slurries undergoing continuous shear go from a pumpable to a non-pumpable state. Once pumping is stopped, the profile of how cement transition from a liquid, to a gel, to a set cement changes. These changes can directly affect the performance of cement slurries to control fluid migration.
With the advent of the Ultrasonic Cement Analyzer (UCA), the term "transition time" of cement slurries was redefined. UCA&s have developed into an essential piece of equipment. Not only can they achieve compressive strength information, but the apparatus can also provide a continuous measurement of how cement sets in static state. This information has shortened wait on cement (WOC) time, and provides an excellent profile on how fast cement develops strength. However, the transducers in a standard UCA only provide information after the cement develops a compressive strength set. With improvement in computerization and transducers, a more sensitive evaluation of gel strength development can be studied.
Another definition for transition time is the use of a static gel strength (SGS) analyzer to measure the time from which cement goes from 100 lbf/100 sq. ft (48 Pa) to 500 lbf/100 sq.ft (240 Pa). It has become an industry standard that once cement slurries reach an SGS of 500 lbf/100 sq. ft (240 Pa)., gas or other fluids cannot be transmitted through the cement. The faster that you achieve this optimum SGS, the less likely that the cement will transmit gas.
This paper will establish a definition for cement transition time and discuss the misconception of only using gel strength development to control gas migration. Test data that exhibits gas tight slurries with long transition and those with short transition that allowed gas influx will be shown. Also discussed in the paper will be the advantages of cements with a short transition in controlling high-pressure water flows.
Crosslinking of Guar and Guar Derivatives
Authors: Lei Cuiyue , Clark P. E. 
Published: December 2007

Abstract
Crosslinking of guar and guar derivatives has played a major role in improving stimulation of oil and gas wells. While crosslinking has been used for a number of years, many facets of crosslinked systems are still not well understood. Part of the problem is that the traditional methods of determining the properties of crosslinked fluids work well for obtaining the data necessary for treatment design, but yield little information about nature of the crosslinked system. A good example of this is found in the development of low polymer concentration crosslinked gels. These gels are important because they lower costs and help to minimize formation damage. In this paper, methods for predicting crosslinkability at low concentrations will be examined.
The polymer literature is filled with methods of characterizing polymer solutions almost none of which find wide use in the development of crosslinked fracturing fluids. Dawson, et. al.,&lt;sup&gt;1&lt;/sup&gt; first reported that the concentration at which a polymer solution transitions from dilute to semidilute could be used as a method for determining the potential for low concentration crosslinking in a guar or guar derivative solutions. This finding was controversial, to say the least. To test this assertion, we have conducted a series of experiments that not only show that the transition concentration is an important indicator, but also present a framework for exploring the potential of other crosslinked systems. Interestingly, polymers that crosslink well at low concentrations do not always produce the best crosslinked gel at higher concentrations. Based on our experiments, we will present an explanation for this finding. This emphasizes the importance of understanding the crosslinking process in order to optimize the selection of a polymer for a particular application.
This paper examines guar and guar derivative systems used in the industry and reports on a new guar that can be successfully crosslinked at low concentrations. It also provides a outline for studying crosslinking at low concentrations and presents insights into the crosslinking process.
Thermally Stable Polycrystalline Diamond Cutters for Drill Bits
Authors: Radtke Robert P. , Riedel Richard , Hanaway John 
Published: December 2007

Abstract
Current research has developed an improved ENDURUSTM TSP (thermally stable polycrystalline diamond) cutter and the potential to increase rate of penetration and bit life in hard and abrasive rock. PDC (polycrystalline diamond) wear rates increase exponentially above 700 °F (372 °C), and PDC fails structurally at 1350 °F (750 °C). The ENDURUS™ cutter differ from all forms of PDC and TSP materials in that they maintain a constant wear rate up to 2192 °F (1200 °C) and are stronger to withstand drilling impact forces. TSP cutters have not generally been economic due to low ROP with small available sizes that are surface-set in drag bits, and because of insufficient attachment and impact strength in the larger self-sharpening PDC configurations. All types of commercially available TSP have insufficient fracture resistance for most applications. Low attachment strength and impact resistance is reminiscent of the limitation of PDC in the 1970&#39;s before a unique LS induction brazing process was developed in the latter 1970&#39;s. TSP can now be brazed with high attachment shear strength using two unique brazing methods – Microwave and Combustion Synthesis Brazing. New TSP manufacturing processes result in a 36% increase in fracture resistance and attachment shear strength over 50,000 psi. (345 MPa). TSP drill bits now have the potential to reduce well cost by 15%, and overall project cost by 7.5%. Thus, the industry could have greater economic incentive to produce deep wells.
Incorporation of Spatial Characters into Volcanic Facies and Favorable Reservoir Prediction
Authors: Tang Hong , Ji Hancheng 
Published: December 2007

Abstract
Compared with clastic reservoirs, volcanic reservoirs are of higher heterogeneity. Lithological facies is one of most important indicators of favorable volcanic reservoir. Traditionally, facies are identified by core observation or log data classification. However, the spatial distribution characters and geological priors, which are important in early stage of exploration, are seldom quantitatively incorporated in facies prediction. Based on previous work, a new methodology is developed to incorporate volcanic spatial information with few well log data (3 wells) to improve the facies prediction accuracy. Such method is applied to volcanic clastic reservoir of Yingchen member, Cretaceous, Xinshan fault depression, northeastern China. Based on the assumption that the residual thickness of volcanic formation is controlled by eruption center, indicator simulation of seismic thickness data is used to estimate the prior probabilities of occurrence of facies. Such prior is combined with well log facies data within a Bayesian framework. Artificial neural network, beta-Bayesian method as well as discriminant analysis algorithm are used to predict log-based facies. Confidence analysis is applied to evaluate the facies prediction. Analysis of variance (ANOVA) proves the overall prediction accuracy is above 82%.
To incorporate updated facies data with geological information (diagenetic facies, potential fractural area and volcanic residual thickness), Indicator kriging algorithm is applied to generate reservoir quality index. Three favorable reservoirs are predicted based on above methodology, which is proved by the subsequent drilling.
Revaporization of Condensate with Methane Flood
Authors: Al-Anazi Hamoud A. , Sharma Mukul M. , Pope Gary A. 
Published: December 2007

AbstractCoreflood experiments were performed to investigate the effectiveness of methane flood in revaporization of condensate phase from cores. Condensate was accumulated dynamically in cores by reducing the flowing pressure below the dewpoint of the flowing gas mixture used. Two-phase flow was continued until steady state was reached where condensate reached its residual saturation. Methane was flooded through the core to assess the revaporization process.Methane flooding revaporizes condensate from the core and restores the gas permeability to its initial value, but it is a slow process. Experimental results showed that revaporization of heavy components by methane is very slow process and may require several 10s or 100s of pore volumes to achieve. The revaporization of condensate is controlled by the partitioning of the hydrocarbon components into the flowing gas phase when the pressure is below the minimum miscibility pressure (MMP). Increasing methane pressure and flow rate expedites the revaporization of condensate.The revaporization of the heavy components in the condensate phase was slightly affected by non-equilibrium behavior at the high flow rates. The return permeability ratio increases with methane volume injected and is relatively insensitive to flow rate, indicating that non-equilibrium effects are of secondary importance. The experimental studies showed promising results for field application.
An Investigation of Non-Darcy Flow Effects on Hydraulic Fractured Oil and Gas Well Performance
Authors: Smith M. B. , Bale A. , Britt L. K. , Cunningham L. E. , Jones J. R. , Klein H. H. , Wiley R. P. 
Published: December 2007

Abstract
The primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to optimize well performance. In permeable reservoirs, the design objective is to achieve a Dimensionless Fracture Capacity, CfD, of at least 2. In lower permeability applications, additional conductivity is required (CfD &gt; 10) to allow effective fracture fluid cleanup and optimized well performance. In some tight formation gas applications, conventional cross-linked gel fracture stimulations are not creating the desired fracture dimensions. The potential reasons for the shorter than desired effective fracture lengths are numerous with the most likely being reservoir heterogeneity, excessive fracture height growth, and poor fracture fluid cleanup.
In recent years, there has been much discussion regarding the causes for, or reasons that the dimensions of the hydraulic fracture are shorter than desired. These include: relative permeability effects, fracture fluid cleanup, multi-phase flow, and non-Darcy flow. The former causes and reasons have been investigated in some detail; however, little data has been published regarding the effects of non-Darcy flow on fracture conductivity and effective fracture length. Some in the industry have suggested that tight gas well performance is hindered significantly by non-Darcy flow effects. This view, though potentially correct, is supported by little actual data in the literature. Further, to mitigate this effect, tip screen-out fracturing techniques and larger fracture stimulation designs often utilizing much more expensive ceramic proppants have been recommended and executed even in very low permeability applications. These methods may not be effective in tight gas applications but they surely are more expensive, potentially eroding the economic benefits of fracturing these low deliverability applications. In addition, little actual well performance data has been presented to justify the importance of non-Darcy flow in fractures with much of the justification coming from the use of semi-analytical calculations and spreadsheets.
This paper will document an investigation of non-Darcy flow to hydraulically fractured oil and gas well performance. The investigation will utilize both a three dimensional single-phase numeric finite difference simulator and actual well performance to investigate the importance of non-Darcy flow to hydraulically fractured oil and gas wells. This paper will demonstrate the following: The importance or lack of importance of non-Darcy flow on hydraulically fractured oil and gas well performance,Compare and contrast actual well performance of off-setting wells where sand and ceramics were utilized in East Texas, Trinidad, and North Sea applications,Develop treatment guidelines and fracture design objectives to limit/mitigate the effects of non-Darcy flow across a broad spectrum of fracturing applications.