bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Mathematical Analysis of Oil and Gas Well Stimulation by Explosive Fracturing
Authors: Laspe Charles G. , Roberts Leonard N. 
Published: December 2007

Abstract
Considerable interest in chemical explosive fracturing has resulted in the derivation of mathematical reservoir models for explosive stimulations. Mathematical models are presented which describe the effects of a chemical explosive displaced into a producing formation and the characteristics of the drainage system within the formation after stimulation. The effects on formation permeability and fracture extension distances permeability and fracture extension distances for different types of formations are derived. Predicted over-all production improvement Predicted over-all production improvement ratios and the economics involved are also covered.

Introduction
In a recent article, a new technique of explosively stimulating the production of oil and gas wells is described by Weigelt and Laspe. The method involves the hydraulic or pneumatic displacement of a powerful slurried pneumatic displacement of a powerful slurried explosive far back within the fracture system of the pay zone. Upon detonation, which propagates through fissures as small as 1/64 in. propagates through fissures as small as 1/64 in. in width, high energy shock waves are initiated. These waves cause extensive rubblizing and secondary fracture generation at considerable distances from the original fissure. In addition, the large quantity of product gases generated by the explosion result in lengthening of the primary fracture system. The rubblized fragments, some of which are in the typical frac sand particle size range, are blown into the newly formed fractures to provide an autogenerated proppant.
A Laboratory Investigation Confirms the Relative Inefficiency of True Miscible Drives, and Outlines New Concepts for Maximizing Oil Recovery by Gas Injection
Authors: Giraud A. , Thomere R. , Gard J. , Charles M. 
Published: December 2007

Abstract
Laboratory displacements of oil by gas at high temperature and pressure have been performed in one and two dimensions using both performed in one and two dimensions using both simple ternary mixtures and actual reservoir fluids. The results have been analysed with the help of a numerical model.
The displacements carried out in the so called "dynamic miscibility" conditions are fundamentally different from true miscible displacements, in particular the conformance appears to be much better when optimum conditions (pressure and/or gas compositions) are selected. These conclusions may be extended to all displacement processes involving mass transfer between phases.

Introduction
Several types of displacement processes are commonly referred to as "miscible", although they do not involve identical thermodynamic conditions. Fig. 1 represents the classical ternary diagram, in which complex hydrocarbon mixtures are schematically described as a combination of three main constituents: methane (C1), intermediate hydrocarbons (C2 to C6) and heavy hydrocarbons (C7+). Although this diagram is only a crude approximation of the complex PVT behaviour of natural hydrocarbon mixtures, it is very convenient and good enough qualitatively for demonstration purposes.
Produced Water Disposal – A Learning Curve in Yemen
Authors: Wilkie D. I. , Kennedy W. L. , Tracy K. F. 
Published: December 2007

Abstract
The success of many oilfields depends upon efficient disposal of produced water. In the case of the Masila block in Yemen, the difficulty of water disposal was underestimated because the high permeability of the production wells led to expectations that high injection rates and economic subsurface disposal would be easily attained.
A number of standard approaches were taken to obtain injection rates of 40,000 BWPD per well. After initial failures, a multi-disciplined team was formed to review the practical and theoretical aspects of formation damage and water quality. Successful injection at rates exceeding 80,000 BWPD per well were subsequently achieved by underbalanced drilling and improving water quality. Two orders of magnitude of increase in injectivity index. Optimizing the drilling and completion methods saved S14MMUS that would have been needed to dispose of water at hydraulic fracturing pressures.
The learning curve and dead ends that led to the successful subsurface disposal of over 200,000 BWPD are described. Perforating, core flow tests, core analysis, corrosion, sand behavior, pressure measurement, drilling fluids, completion configuration, filtration and remedial stimulation are discussed.
Deepwater Skid-over Solution for Marginal Field Development at the Froy Field
Authors: Smidth Frederik , Georges Christian 
Published: December 2007

Abstract
1 Drilling in skid-off (tender assisted) mode from a cantilever jack-up has been done on several occasions worldwide including the North Sea (ref. 1).
This paper describes the utilization of the "MAERSK GALLANT", an MSC-C.T62S jack-up drilling rig, at the FROY Field in the North Sea in Skid-off Mode.
FROY is located 35 km SE of the Frigg Field off Norway in a water depth of 120 m. The field is developed with a light, unmanned platform. The topside is comprising a well bay area with 15 slots and a process area with a test separator, a gas/liquid separator and export pump only. No drilling facilities are built on the WHP. Four wells were pre-drilled with a semi-submersible rig. Tie-back and completion of these first four wells and completion and drilling of the six remaining wells were performed by the jack-up "MAERSK GALLANT" in skid-over mode (fig. 1).
Several development scenarios were studied. The reason to develop this field with this alternative, even in this extreme environment, was to minimize weight and cost; the jacket structure is 6,000 mT and the topside only 2,375 mT. It has also been a focus in the design of the skid-over solution itself and thereby make it more or less "field specific", compared to previous skid-off solutions for ultra harsh environment jack-ups (ref. 1).
Another consideration was the water depth of 120 m, which is a North Sea record for jack-ups, and the associated relative movements between the production platform and the rig.
The end result, however, was a highly flexible design which can be utilized on a large number of field developments with only minor adjustments.
All setting up of drilling facilities on the platform were done from the jack-up without any assistance from the platform, crane barges or similar.
As for the drilling operation all "support" from the production platform is two skidding beams with a spacing of 14.0 m (46 feet).
The design optimization was done as a joint effort between the Operator (ELF NORGE) and Maersk Drilling. The success of the project emphasized the importance of close cooperation between the operator and the contractor as early as possible in connection with field development projects.
Slim Hole Drilling and Well Intervention from a Light Vessel
Authors: Carstens E. , Ervik G. A. , Gleditsch S. 
Published: December 2007

Abstract
Drilling in deep waters is a costly venture. This paper discribes how the method of slim hole drilling may be applied to reduce those costs. A system is designed for 5000 ft water depths which incorporates a heave-compensated singles rig and high pressure riser. The rig is fully heave-compensated while tripping and drilling allowing better control of downhole operations. The high pressure riser dispenses with the need for kill and choke lines. The smaller and simpler design enables use of quick couplings, and bouyancy elements are not needed. The vessel is dynamically positioned. The subsea system is designed to allow for drift-off to occur with the riser intact and well control maintained. This paper describes the system and tests and evaluations done to determine system cost and efficiency. A market evaluation shows that the highest potential for cost reduction is for subsea well intervention and deep water exploration drilling.
Evaluation of Oil Soluble Resin Mixtures as Diverting Agents for Matrix Acidizing
Authors: Crowe C.W. 
Published: December 2007

Abstract
A new oil soluble resin mixture has proved extremely effective as a diverting agent for matrix acidizing treatments. The mixture has three major advantages which make it a more effective diverter than other agents currently in use:
1. It effectively equalizes flow into zones of varying permeability.
2. It is completely oil soluble and leaves no residual formation damage.
3. It can penetrate a gravel pack and divert in the formation behind the pack. It is the only diverter which is effective for this application at temperatures above 125degrees F.
One of the major factors controlling the success or failure of any sandstone matrix acidizing treatment is that of proper distribution of the treating acid over the entire producing interval. Unless an effective diverting agent is used, the largest portion of the acid may be expended on only a small part of the total zone.
A study was made of the various diverting agents presently used in matrix acidizing. These diverters were evaluated in terms of (1) their ability to equalize acid flow into zones of varying permeability, and (2) clean-up following the treatment without residual formation damage. Diverters evaluated included viscous gels, natural gums, emulsions, acid swellable polymers, solid organic acids and a new system employing a mixture of finely divided oil-soluble solids.
Of the materials tested, some were found to be totally ineffective while others produced extensive formation damage. Best diversion was obtained with the swellable polymers or the mixture of oil soluble resins.
This paper presents data comparing effectiveness of various matrix diverters. The diversion mechanism of the oil soluble resins is described and case histories are presented to show how better diversion improves production increases.

Introduction
In recent years, renewed interest has been shown in the use of hydrochloric-hydrofluoric acid mixtures for the matrix treatment of sandstone formations.
Rheology Design to Optimise Rate of Penetration
Authors: Maidla E. E. , Reay A. J. , Beck F. E. , Tan C. P. 
Published: December 2007

Abstract
A Bit Reynolds Number optimization algorithm has been developed in response to the field observation that this maximizes the rate of penetration regarding bit hydraulic effects.
Discussion on the reasons for such behaviour are undertaken and some common drilling scenarios are presented for which Bit Reynolds Numbers would be of use.
A field case study shows good agreement between the theoretical optimum and the field results.
A possible downside for maximizing Bit Reynolds Numbers is also addressed concerning wellbore stability.
Critical Evaluation of Blast Furnace Slag Mud Converted to Cement
Authors: Sabins F. L. , Edwards T. M. , Maharidge R. L. , Weiss M. 
Published: December 2007

Abstract
This paper summarizes the results of a Joint Industry Project investigating the performance of mud converted to cement using Blast Furnace Slag (BFS). This paper compares BFS/muds to conventional Portland cements in various simulated cementing applications. This project covers the test results from converting dispersed and PHPA drilling fluids to cement, in comparison to conventional low fluid loss Portland cements in three main areas. The first tests simulated a geopressured gas well by use of a large scale gas migration model. Secondly the dimensional stability of the BFS/mud is presented. Dimensional stability measures the total volume reduction at temperature and pressure during the hydration process. Finally the mechanical properties of the system are also presented including: compressive, tensile, and shear strengths and long term creep under confining loads. The tests showed that the BFS and the Portland systems display similar physical characteristics, but do exhibit some differences. Common traits were: hydration volume reduction, pressure reduction due to volume losses and gellation, compressive strength, shear strength and long term creep. In the limited testing performed the BFS/mud system, however, did exhibit much lower tensile strengths and demonstrated an inability to maintain a long term gas seal in the latter stages of hydration. Further testing is planned to better understand this latter phenomenon. A detailed analysis of this data is given in this report.
Liquid Cement Premix Introduces New Solutions to Conventional Cementing Problems
Authors: Rae Phil , Johnston Neil 
Published: December 2007

Abstract
Oilwell cementing has changed very little in the past 70 years. However, a new process has been developed that radically changes the way in which cementing operations are conducted. A new understanding of material properties has allowed the design of novel cementing systems, with remarkable performance characteristics, that can be mixed more easily in the field. These slurries can be accurately mixed with simple equipment but, if required, the process can be fully automated.
Control of critical slurry parameters, such as density, rheology, thickening time and compressive strength development can now be achieved with unprecedented precision without the use of batch-mix tanks or other ancillary equipment. Using this process, continuous ("on-the-fly") cementing operations can be conducted at rates ranging from 0.1 – 3.5 cu. m per minute (approximately 0. 5 – 20 bbls/min) without the problems that typify today's methods. Slurries that can be prepared in this way cover the wide density range encountered in the majority of cementing applications, 1320 – 2500 kg/cu. m. (11 – 21 lbm/gal). Furthermore, slurry properties can be continuously modified throughout the operation, if required, to take account of well temperature profile, etc. Such procedures help reduce waste and minimise environmental impact of the cementing operation.
The new process can be used advantageously both for primary and remedial cementing operations and is applicable both on-land and offshore. We believe the greatest benefits can be realised in the offshore sector initially since the process lends itself to full automation, permitting reductions in personnel-on-board, improved safety and reduced rig time. Ultimately, the improved wellsite quality control achieved with this system will translate to a higher percentage of successful cementing operations and a net reduction in cost for the operating companies.
High Performance Water Reduced Cement Slurries Prepared With Low Cost Optimized Blend
Authors: Baret J. François , Garnier Andre , Rashad Basil 
Published: December 2007

Abstract
A cement slurry is a suspension of solid particles in an aqueous solution. Slurry properties depend on many variables: the amount and nature of the solids, including cement, the additives used, the amount and the type of water, the temperature and the pressure.
For a given solid blend, the water-to-solid ratio determines the slurry density. In the new approach to cementing described in this paper, differently to what is done traditionally, a blend has to be chosen as the first step in the system selection. Here the blend choice is a process which implies the identification of the materials providing the specific gravity required and the determination of the optimal ratios between these different components.
Blend quality is an essential parameter which plays a role, directly or indirectly, in all slurry properties.
Optimization of Drilling Performance in Argentina through a New PDC Bit Generation
Authors: Besson A. , Delwiche R. , Lamine E. , Dekoster C. 
Published: December 2007

Abstract
The lithology of the North West of Argentina presents two major portions where PDC bits have not succeeded in the past. The first portion was mainly made up of alternating sands and shales with spot zones of conglomerates erratically encountered. The second portion was made of dense shales and cemented sandstone stringers, with altemances of limestones. In spite of acceptable performance on the top portion, conventional PDC bits faced premature failures when the compacted sandstones and limestones were faced. Rock bit performances were usually in the range of ± 6 to 7 m/h and the footage around 360 m. The section was drilled with five to six bits for a total drilling time of 220 hours. The introduction of a new generation of PDC bits allowed to triple the ROP and increase by five times the potential footage.
This paper describes the methodology and shows the efficiency of a good partnership between the operator and the service company; a good level of communication, a knowledge of mutual skills and expectations, as well as a prompt reaction from both sides led to the definition of a reliable product using the latest developments of the PDC bit technology:
the ability to control the quality of the PDC cutters, the use of an advanced cutter lay out defined by 3-D software, the use of CFD code for optimized cleaning and cooling, the mastering of vibration reducing features, including spiralled blades etc.
Savings in the range of 200,000$ per well were recorded at the first trial of a drilling program. Fine tuning of the technology and parameters now allow savings beyond 350,000$ per well.
New Hard Formation Roller Cone Bit Technology Improves Economics of Abrasive Travis Peak, Cotton Valley Wells
Authors: Watson P.A. , Welch R.M. , Scott D.E. 
Published: December 2007

Abstract
The typical gas wells drilled in heavily explored Panola County of East Texas encounter the highly abrasive Travis Peak and Cotton Valley formations at around 6,300 ft. The Travis Peak is normally reached at 6.300 - 6.500 ft, followed by the Cotton Valley from 8,000-8,300 ft to TD. The Travis Peak and Cotton Valley are each about 1,700-2,000 ft in length. Until recently, the extremely abrasive sections in these formations severely limited the life of the IADC Class 537 through 737 roller cone bits used to drill these wells. Between severe gauge and cutting structure wear, the bits run previously were normally pulled after about 600 ft of drilling. The shortened life meant six to 10 bits were required to complete the two intervals.
This paper describes the design and application of new hard formation rock bits that are drilling up to 50% more footage than the 627 and 737 types run previously. The new IADC Class 647 and 747 roller cone bits incorporate new insert geometries and quantities. along with improved carbide grades and diamond-enhanced gauge protection. Today, the Travis Peak and Cotton Valley are being drilled with four bits, averaging more than 850 ft per bit. Along with the new bits, a revised mud program consisting of low-solid polymers contributed to the improved performance realized in recent Panola County wells.
The authors will review the design process of the new bits. as well as presenting case studies of typical Travis Peak and Cotton Valley wells in Panola County and elsewhere in East Texas.

Introduction
The East Texas field was discovered in 1930 with the Joiner-Daisey oil well, Drilling had focused primarily on the shallower and highly productive oil bearing formations. While gas wells have been producing from the Travis Peak for more than 50 years, and gas sands were discovered in the Cotton Valley in 1937, it was not until 1968 that the first producing Cotton Valley gas well came on stream in Panola County. The Natural Gas Policy Act of 1978 and the Federal Energy Regulatory Commission's (FERC) tight gas sand policy of 1980 spawned interest in the gas reserves of the Travis Peak and Cotton Valley. Today, the focus of East Texas exploration is the marginal gas reserves. Fig. 1 outlines the East Texas area where most of the gas drilling takes place.
Stratagraphically, the lower Cretaceous Travis Peak comprises fine-grained to very fine-grained sandstones, muddy sandstones and sandy mudstones The sandstones are highly cemented and consist primarily of quartz with quartz cementation. Owing to the extremely cemented nature of Travis Peak sandstones, as confirmed in laboratory tests, the rock fails by fracturing the individual quartzitic sand particles, which accounts for the extremely abrasive nature of the formation.
P. 595
One Year Experience in Slim Hole Drilling
Authors: Sagot A. , Dupuis D. 
Published: December 2007

Abstract
Further to previous research and experimental wells drilled in 1993, in 3" and 3 3/8" ("Les Talonnieres", SPE Paper n•28299), and the decision to built the fitted for purpose Slim Hole rig FORASLIM 1 commissioned in April 1994 (SPE Paper n•28867, a Fitted for purpose Rig) 6 Slim Hole wells have been drilled for ELF AQUITAINE : 2 in the Paris Basin and 4 in (Gabon) West Africa.
Eighteen months of experience allow to make a global review of what are the achievements in terms of geological data acquisition, drilling performances, and economical results. This permitted to point out the weaknesses and the corresponding needed improvements to reach a mature Slim Hole technology fully comparable to the conventional approach.
The paper describes and analyses the operational results of each well as different prospects were drilled in respect of depth, geology. One significant experiment in a well drilled in 3 3/8" with high pressure at 3310 m (11 000'), requiring the use of mud weight of 1,75 sg (14,5 ppg) is in particular described.
Beside the review of drilling performances and geological data acquisition, an economical review will be made. A cost comparison with conventional approach provides an estimation of the benefits of the Slim Hole approach.
The potential use of a Slim Hole drilling offshore and for deep wells is finally presented.
Coiled Tubing Drilling Practices at Prudhoe Bay
Authors: Goodrich G. T. , Smith B. E. , Larson E. B. 
Published: December 2007

Abstract
Recent drilling experience has led to significant improvements in coiled tubing drilling (CTD) operations at Prudhoe Bay. Since implementation of a full time CTD program in mid 1994, over two dozen open-hole drilling operations have been performed in the Eastern Operating Area (EOA) of the Prudhoe Bay Field. Drilling programs have included simple extensions from pre-set liners to more complex through-tubing horizontal sidetracks. Horizontal sections greater than 1200 feet have been drilled. Measured depths in excess of 13,000 feet have been reached using two inch diameter coiled tubing with 3-3/4 inch bits. This paper will address current CTD techniques used at Prudhoe Bay and compare these techniques with rotary drilling methods.
Coiled tubing drilling techniques have evolved in response to drilling mechanics and hydraulics limitations of coiled tubing workstrings. Bottom hole assemblies (BHA) are designed to improve weight transfer. MWD directional package sensors are located as close to the bit as possible (11 to 12 feet) and directional changes are made incrementally to minimize dog leg severity. Less aggressive PDC style bits are used to reduce reactive torque and mud motor stalling. Drill rates of 10 to 20 feet per hour (fph) in shales and 30 to 70 fph in sands are typical. Bit wear is often negligible. Motor life or directional requirements typically limit a bit run.
Weight transfer, hole cleaning, and stuck pipe problems in high departure sections have been reduced through the use of low solids (less than one percent) polymer drilling mud. To improve hole cleaning and prevent cuttings bed build up, rates of penetration are controlled and short trips while circulating are performed frequently. Mud lubricants have improved weight transfer while drilling overbalanced.