bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis Of The Response Of Geothermal Reservoirs Under Injection And Production Procedures
Authors: Lippmann Marcelo J. , Tsang Chin Fu , Witherspoon Paul A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A major problem facing geothermal operations is the disposal of large quantities of relatively cool waste geothermal waters. Environmental regulations may require reinjection into the reservoir. Since the reservoir is thus cooled around the injection wells, there is some reluctance to reinject into wells that might be used for future production. production. In this paper the response of a liquid-dominated geothermal reservoir to injection and production from a single well is studied. Different production from a single well is studied. Different injection-production schemes are analyzed to explore how to minimize temporary cooling around the injection well and to optimize thermal recovery. The pressure response is also calculated, and found to be affected significantly by temperature-dependent viscosity variations. This will have implications on well-test methods for geothermal reservoirs. Vertical consolidation of the geothermal system during fluid withdrawal is also discussed, showing the need to establish previous stress history before attempting to previous stress history before attempting to predict the reservoir deformation. predict the reservoir deformation. The transport of heat and fluid through a porous reservoir is computed using a numerical porous reservoir is computed using a numerical model developed at the Lawrence Berkeley Laboratory. The one-dimensional consolidation theory of Terzaghi has been coupled to the heat and fluid flow to calculate reservoir compaction. attempt is made to model chemical reactions or precipitation that might occur when waters of a precipitation that might occur when waters of a different temperature and salinity are injected into the reservoir.

A. Introduction
A major problem facing geothermal energy development is the disposal of large quantities of relatively cool waste geothermal waters. Operators are reluctant to reinject these fluids as they could irreversibly cool the reservoir around the injection wells and affect nearby producing wells.
Gringarten and Sauty used a two-dimensional semianalytical model to investigate the effect of reinjection wells on neighboring producing wells. Tsang, and Witherspoon used the same model to suggest the screening effect that may be found in a multiple-well system. However, this model assumes a steady fluid-flow field, neglects gravity and, even more important, ignores the dependence of parameters (such as viscosity and density) on temperature variations. Thus a detailed understanding of the behavior of a geothermal reservoir cannot be expected with this semianalytic approach.
Realistic two- or three-dimensional numerical models have been developed to analyze liquid-dominated geothermal systems (Mercer and Pinder; Pritchett et al.; Sorey, and others). Pritchett et al.; Sorey, and others).
A core based comparison of the reaction characteristics of emulsified and in-situ gelled acids in low permeability, high temperature, gas bearing carbonates
Authors: Lynn Jack D. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
There are a number of acid formulations that will generate deeply penetrating wormholes in carbonate formations. Two of the most recent advances are diesel emulsified acid (DEA) and self-diverting polymer/HCl (in-situ gelled acid, or GA). The acid volumes required for propagation of the wormholes, as well as the characteristics of the wormholes are significantly different in each of these formulations. Two different service company implementations of GA, and one inhouse developed DEA formulation were evaluated for stimulation of a high temperature (250°F, 121°C), low permeability Saudi Arabian gas and gas condensate producing carbonate.
In this paper, the reaction characteristics of DEA were compared to GA formulations using reservoir condition core floods. The characteristics of the acids that were compared included wormhole propagation rates, volumes of carbonate consumed by the acids, wormhole geometric characteristics, and pressure response during injection. Since the acid formulations called for 28 percent HCl acid concentrations, high temperature stability and corrosion control chemicals of the packages were evaluated.
The core study found that the GA formulations enhanced the permeability of core samples significantly more then the emulsified acid. The DEA was the more stable of the acid formulations at 250°F. Both of the GA formulations showed some degree of separation of the corrosion control components at reservoir temperature.
The GA was found to require larger volumes of acid to achieve an equivalent penetration distance versus the DEA, and logically, the GA dissolved a larger volume of rock per volume of acid injected. The DEA has a higher rate of wormhole propagation and the DEA leaves no residual material in the generated wormholes. The GA left a residuum of polymeric material in the wormholes even after high rate injection condensate.
Iron precipitation was noted on both the core injection and production faces with all of the acids after spending. The two acids types showed individual characteristics that can be applied to acid frac applications, but full understanding of the behavior of each, tested with specific reservoir core is required for a correct acid selection to be made. In specific applications, both acid types can be combined in a multiple stage treatment to result in significant enhancement of acid frac simulations.
Improved Horizontal Well Placement and Performance Using a Bit Inclination Measurement Tool
Authors: Muritala Lateef , Onwuazo Charles , Adewumi Femi , Aibangbe Osaretin 
Published: December 2007

Abstract
Accurate geological placement of a lateral in the sweetest portion of the reservoir plays a major role in optimizing production rates and increasing recovery from horizontal wells, particularly for complex reservoirs with heterogeneous features. Horizontal wells have thus been routinely steered both geologically and geometrically using evaluation measurements from conventional bottom hole assemblies with sensor points some 50 feet away from the bit. This implies that correction runs and it’s effective response time and footage will be dependent on directional drilling personnel proficiency and tool performance relative to formation type. It is not surprising thus, that a sizeable part of the reservoir is drilled sub-optimally, and in some cases the eventual well bore undulation has caused impossible completions, developed water sumps and have also given birth to speedy breakthroughs of gas and water. All of these have impacted production negatively, and caused unnecessary oil deferment, early work-over and associated cost overrun on budget.
The ideal option would thus be to minimize the undulation while geo-steering the lateral along the sweetest portion of the reservoir in an attempt to minimize attendant production problems and hence allow efficient and early completions.
A tool has been developed which measures well bore inclination 1 foot away from the drilling bit. Shell West Nigeria introduced the At bit Inclination measurement tool to horizontal well drilling on the Opukushi 26 well in March 99. This was to complement multiple depth propagation resistivity and quadrant density-neutron measurements while drilling utilized in horizontal evaluation, to enable full wellbore geologic steering with optimized response time for correcting changes in the desired direction. The result is a significant improvement in the ratio between actual versus predicted production figures as compared to previously drilled wells executed without the combination measurement. It also aided geosteering decision, improved directional performance and enhanced delivery of better quality well.
This paper therefore reviews the SPDC horizontal wells experience in identifying the impact of deviation profiles and lateral placement with respect to production performance, and how the use of the near bit inclination tool along with the formation evaluation measurements has resulted in noticeable improvement.
Short-Radius Drilling Performance Improvement in Algeria
Authors: Neal P. , El-Demerdash A. , Benamor B. , Zeghouani R. 
Published: December 2007

Abstract
This paper describes the benefits resulting from collaborative efforts in solving short radius drilling challenges in the Hassi Messaoud field in Algeria. The core of the collaboration was a team of engineers and geologists from the operator, bit manufacturer, directional drilling and measurement while drilling (MWD) contractors. The team shared information on the characteristics of the field, identified directional problems related to motor selection, adjusted bit selection, and utilized directional drilling expertise, resulting in a reduction in overall drilling cost of over 30%. The following case study highlights cost savings and technical advancements achievable through close cooperation between the operator and service companies.
Improving Drilling Performance by Applying Advanced Dynamics Models
Authors: Dykstra M. W. , Neubert M. , Hanson J. M. , Meiners M. J. 
Published: December 2007

Abstract
Drilling dynamics models play an important role in drilling performance optimization. These models can be classified as engineering tools or research tools, depending on functionality. Engineering tools are designed for everyday use; they provide estimates of important parameters for planning purposes, such as natural frequencies and buckling loads. Research tools describe the physics of the problem more completely, and thus are more powerful. They allow complex phenomena to be studied in great detail, but require a greater investment of time and effort. Both types of models require validation, either through laboratory testing or controlled field tests. Once confidence in the models is established they can be used in a number of ways, including component design, bottom hole assembly (BHA) design, and investigation of component contributions to overall drilling system performance.
Application of advanced dynamics models within one major service company has provided some valuable lessons. Examples include: (1) polycrystalline diamond compact (PDC) bit designs can be adjusted to minimize impact damage to cutters; (2) roller cone designs can be adjusted to reduce off-center running tendencies; (3) BHA stabilization can be optimized to protect sensitive downhole equipment; (4) BHA designs that are unstable can cause rapid bit destruction; (5) operating parameters can be adjusted to improve performance of sub-optimal drilling systems.
Case studies from disparate drilling applications around the world have demonstrated that performance can be improved by applying lessons learned from advanced dynamics models. Operators have experienced significant savings in rig time stemming from reduced tool failure frequency and increased drilling efficiency. Greater tool longevity and reduced maintenance costs have also benefited the service company.
Research Into Lubricity, Formation Damage Promises to Expand Applications for Silicate Drilling Fluids
Authors: Alford S. , Dzialowski A. , Jiang P. , Ullmann H. 
Published: December 2007

Abstract
Silicate drilling fluids have been used for more than 60 years. While the early versions of silicate-base systems proved very inhibitive, controlling mud properties was difficult because proper polymer additives were not available for maintaining rheology and fluid loss control. Furthermore, the solids control equipment available at the time was ineffective in removing solids. During the last decade, silicate-base systems have been re-engineered to provide a state-of-the-art and environmentally acceptable, water-base system that provides the inhibition approaching that of an invert emulsion fluid.
The proposed mechanism of inhibition is the surface adsorption and chemical reaction of the silicate polymer with the formation surface. This "coating" effectively provides a thin pressure and chemical barrier on the surface of the wellbore. This formation/silicate interaction has raised a number of concerns regarding both the lubricity and the formation damage potential of the fluid.
This paper investigates systematically both the lubrication characteristics of the fluid and the effect of silicate-base systems on formation production and evaluation. The results show promise in expanding the application of silicates as reservoir drill-in fluids and in the drilling of critical high-angle wells where lubricity is a primary design criterion.
The data obtained in this study utilizes purpose-built lubricity and formation damage equipment to critically look at the problems. From this investigation the authors will reveal that the coefficient of friction of silicate fluids, as observed in the laboratory and measured in the field, does not differ significantly from that of other water-base fluids.
Furthermore, the thin physical and chemical barrier formed during the reaction of the silicate polymer with the formation surface prevents fluids and fine particles from migrating into the formation, thereby minimizing damage to the producing zone.
Application of Multilateral Well Technology in the Deep Waters of the Campos Basin: History and Probable Evolution
Authors: Sotomayor Gabriel , Oliveira Ronaldo , Alves Ivan 
Published: December 2007

Abstract
This paper presents some of the experience of drilling and completing level 4 and 5 multilateral wells in deep waters of the Campos Basin, in the last three years. It presents the reason for this initiative, a general description of the several types of junction building processes (both milled and pre-milled window systems) and some aspects of the wells that were drilled and completed: the Bonito well (water depth:200m); Voador well (water depth: 565 m) and the two Barracuda wells (water depth: 802m/ 850m). This paper also shows the lessons learnt during these complex projects and concludes that the multilateral well technology became a viable alternative for subsea development.
A New Look at Deepwater Drilling Problems Combined with New PDC Technology Produces Savings of $5.9MM
Authors: Newhouse C. C. , Fielder C. M. 
Published: December 2007

Abstract
During project execution planning for a Gulf of Mexico (Green Canyon) deepwater project, the well construction team looked at all possible options that might reduce time on each well. This investigation indicated that the biggest opportunities in the drilling phase were increased ROP and reduced number of trips.
The original plan had included the use of underreamers and roller cone bits. It was known that PDC bi-centers were a cost effective replacement for underreamers due to their ability to simultaneously drill and underream. Also, that ROP was higher with PDC bits (both bi-center and conventional PDC bits). Previous use of PDC bits had, however, resulted in hole-cleaning problems due to the large volume and type (gumbo) of cuttings. Problems were also historically encountered with PDC directional characteristics, especially kicking off in the larger hole sizes and angle dropping in the tangent sections. Based on the recent introduction of new PDC technology it was decided to take a new look at making PDC bits more effective.
To counter the problem of hole cleaning, it was decided to increase flow rates by utilizing a larger drill string. In the upper section of the well where underreaming was planned, a new type of bi-center was used. The bi-center used new technology that allowed it to drill out (saving an additional trip over conventional bi-centers). In the lower section, a radically new PDC drill bit design was used that contained features to significantly increase ROP. Both of the new PDC designs contained new features to significantly improve directional characteristics. A variety of other improvements/modifications are mentioned in the paper.
Results: The new technology bi-center bits (17 × 20 and 14 ½ × 17 ½), provided the biggest time savings by eliminating trips, producing very high ROP, and successfully kicking off and building angle (one case as high as 68 degrees). The new PDC drill bits used in long tangent sections (one was 9300’ at 63 degrees) had ROPs that in most cases doubled that of similar offsets while reducing slide times to as little as 1%. The new plan resulted in four wells being drilled in 115 days less than the original project AFE estimates (52% reduction), for a savings of $5.9MM.
Reducing Drilling Costs in Deep-Water Gulf of Mexico Utilizing Two Piece Drill Out Reaming Technology
Authors: Watson Patrick A. , Kolstad Eric S. , O‘Grady Thomas T. 
Published: December 2007

Abstract
The application of modified reaming technology in Mississippi Canyon, deep-water Gulf of Mexico (GOM) has had a beneficial impact on drilling costs. The ability to drill cement and associated downhole float equipment with steerable ream while drilling (DOSRWD) tools has become increasing important in deep-water GOM drilling. The extra trip required by conventional bi-center and eccentric tools adds costly "flat" time to a well’s drilling program. Additional improvements in the eccentric bit’s geometry and cutting structures has reduced the number of trips and significantly lowered drilling costs. Traditionally, when a ream while drilling system was used, the operator drilled the cement and float equipment with a pass through size bit, then tripped out of the hole to pick up the ream while drilling bottom hole assembly. For example, float equipment and cement in 9–5/8" 53.5# casing was drilled out with an 8–1/2" bit. A trip was then made to pick up a standard 9–7/8" SRWD bottom hole assembly.
The DOSRWD’s ability to drill cement and float equipment inside casing and then continue drilling ahead, plus the option to use either a tricone or PDC pilot bit depending on directional requirements and formation type make it the appropriate tool for the application. Water-based fluids are preferred in the upper hole section while synthetic mud is used deep in the wellbore. Because of balling concerns in WBM and stringent directional requirements, the operator utilizes metal bearing seal steel tooth pilot bits in most cases (IADC 117). The authors will document rig cost savings ranging from US$40,000 to $105,000 per trip in some applications with total savings exceeding US$388,000 in some instances.
Through Tubing Well Construction
Authors: Moss Gary , Kuyken Chris , Maessen Frans 
Published: December 2007

Abstract
The Northern Business Unit (NBU) of Shell U.K. Exploration and Production (Shell EXPRO), operating on behalf of the Shell / Exxon Mobil co-venture, comprises the Northern North Sea assets of Brent, Cormorant, Tern, Eider and Dunlin platforms and several sub-sea developments. These mature assets with increasingly marginal accumulations to target have required a broad approach to reduce drilling cost and or increase the NPV from a well bore. This has been successfully achieved by a synergetic approach of the combination of optimising the contracting strategy, implementation of the Deliver The Limit™ Philosophy and by the speedy implementation of novel technology. One of these technologies is Through Tubing Drilling (TTD). In the NBU this enabling technology has been applied since 1996 both in the form of Coiled Tubing Drilling (CTD) as well as Through Tubing Rotary Drilling (TTRD). This has yielded a total of 8 TTD applications (6 CTD, 2 TTRD) making the NBU a dominant North Sea TTD operator who has achieved a unique learning curve.
The objective of this paper is to explain the TTD work that was performed in the NBU and how this has evolved from primarily CTD into TTRD. This change took place as a result of major changes in the business case as well as in reservoir conditions having a large impact on the risk of drilling these wells both from a technical and cost perspective. The paper covers the full NBU TTD Campaign since 1996 but the main focus will be on the Brent CTD campaign (1999) and North-Cormorant CN18S-5 TTRD well (2000). Key learning from a business perspective is that the CTD wells in Brent will be challenging to drill for less than £2.5 million whilst the latest North Cormorant TTRD well was drilled for £1.5 million with significant scope for further cost reduction.
Design of Water Based Drilling Fluid Systems for Deepwater Norway
Authors: Sørgård Eirik , Alterås Eva , Fimreite Gunnar , Dzialowski Andrew , Svanes Grete S. 
Published: December 2007

Abstract
The technical demands placed on drilling fluids used in the deep waters of Norway differ dramatically from those encountered in any other deepwater basin. Unlike the deepwater of the Gulf of Mexico, West Africa or Brazil, seafloor temperatures here can dip as low as –2.5° C (27.5°F), with low ambient surface temperatures the year round. These characteristics combined with constantly changing sea conditions and some of the world's most stringent environmental restrictions, makes the engineering of drilling fluid systems for Norwegian North Sea wells an arduous effort.
This paper describes the innovative development and qualification of a water-base drilling fluid system engineered for a well to be drilled in 837 meters (2745 ft) of water off Norway. The pre-qualified fluid was required to inhibit hydrates under normal drilling conditions and possess excellent shale inhibition characteristics to support hole stability and avoid bit balling. Since the primary objective was to obtain a non-contaminated formation water sample, the system must possess superb fluid loss control so the operator could avoid a full drill stem test, thereby saving some US$8 million. Furthermore, the qualified system would have to meet local environmental regulations for offshore discharge of cuttings and excess fluids.
The authors will discuss the development protocol, the qualification of the novel fluid system and its application in the technically demanding Norwegian well. During the development phases, two hydrate testers were qualified and employed in both designing the fluid and to monitor its hydrate inhibitive tendencies during drilling. In addition, the particle size distribution and polymer concentration were engineered to reduce the filtrate invasion, while polymers were specially selected for improved rheological parameters to cope with the cold temperatures. The behavior of a number of glycols and salts were characterized prior to the start of drilling.
The practical approach to qualify the novel fluid system will be explained in detail, emphasizing its use as a guideline to help non-fluid specialists design drilling fluids for this unique deepwater environment