bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsurface Safety Valves for Gas Storage Wells
Authors: Gant Guy W. 
Published: December 2007

Gant, Guy W., Member SPE-AIME, Otis Engineering Corporation

Abstract
Increased value of product, protection of life and personal property have created a demand for downhole safety valves in gas storage wells.
Subsurface safety valves have been used for more than 35 years throughout the world in oil and gas producing wells. However, most of these valves were installed in wells producing native hydrocarbons and do not have a predictable pressure decline. The varying predictable pressure decline. The varying pressure in gas storage wells will generally pressure in gas storage wells will generally require a downhole valve that is controlled from the surface if it is to afford maximum protection. Additionally, the valve should protection. Additionally, the valve should permit maximum production with minimum permit maximum production with minimum pressure drop for peak production periods. pressure drop for peak production periods. Therefore, the development of safety valves for gas storage wells was necessary. These valves are controlled from the surface and do not recognize variable flow rates and declining formation pressure.

Introduction
There are needs for both surface and subsurface safety equipment in the natural gas storage industry. Because of the importance of protecting the product while still in the well and since it is easier to do so - the subsurface safety valve offers maximum protection and will be considered in this paper. The consensus of operating people for the ideal safety valve for gas storage wells will embody the following features:The valve should be designed to permit installing and retrieving by wireline underpressure.Should be controlled from the surface.Permit maximum production rates.Permit injection and withdrawal of product.Have through conduit to permit running pressure surveys, logging instruments, etc. without the necessity of pulling the valve assembly.Must be capable of operating in a dry environment such as experienced in most gas storage wells. (No Lubricant).Should be simple in design - with aminimum number of moving parts.Should be field be repairable.The valve should permit testing when desirable to do so.
The Theory, Methods of Application and Results of the Use of 100 Mesh Sand in Stimulating Permian Basin Formations
Authors: Thompson Jack C. 
Published: December 2007

Introduction
The use of 100 mesh sand in well stimulation is not new. What is new is the method of application to gain outstanding results in Permian Basin formations. Permian Basin formations. A year's history and field experimentation has given a positive insight on how best to use 100 mesh most effectively, especially the concentrations and volumes that seem best suited to the different formations. Optimum volumes have not been established with absolute certainty—and may never be; but field experience has established trends that should be designed into the jobs to assure the greatest probability of success.
The basic method of application is to hydraulically initiate or fracture into the formation with a pad fluid. Then, a slurry of 100 mesh sand is introduced which effectively reduces leakoff through any intersecting "hairline" cracks which are encountered. The 100 mesh does not restrict fluid travel down the principal fracture, and thus allows the subsequent fracturing fluid to extend the principal fracture to the desired distance into the reservoir. Once this hydraulic control is established, the principal fracture can then be propped with larger principal fracture can then be propped with larger frac sands, or the fracture faces of a carbonate rock can be etched with acid just as they are in conventional treatments. Therefore, this particular use of 100 mesh sand is primarily particular use of 100 mesh sand is primarily as an added conditioning step in the pad fluids of a stimulation treatment. In partially depleted zones which have been heavily acidized, it is necessary to use large volumes of 100 mesh sand in order to fill all the previously created void so that the new treatment can enter previously untreated portions of the zone. portions of the zone.

THEORY
For a number of years, calculated penetrations for both acid and fracturing penetrations for both acid and fracturing jobs and consequently the folds of increase to be expected have not been achieved by actual well performance in our carbonate reservoirs. Many things were tried to correct this deficiency—such as higher or lower pump rates, more exotic fluids, more or different fluid loss materials, larger volumes, etc. Still, the actual well performance was most often less than that performance was most often less than that which is predicted.
Current Completion Practices in Tight Reservoirs
Authors: Webster Kale 
Published: December 2007

Webster, Kale, Member SPE-AIME

Abstract
This paper describes the current completion methods being used in "tight" or low permeability reservoirs of the Austin Chalk, Canyon Sand and Morrow Sand.
Formation damage has been a major consideration in all of these reservoirs and has strongly influenced the drilling mud, testing, cementing, perforating and stimulation. All of these factors influence the completion practices and are described for each reservoir. practices and are described for each reservoir. The Austin Chalk in the Pearsall Field is often described as producing from natural fractures. The method of finding these fractures includes coring, logging, and in some cases slant hole drilling through the pay section to intersect more of the fractures. Three basic fracturing fluids and methods have been used to treat the Austin Chalk and the average treatment now costs $35,000.
The Canyon Sands of Sutton and Ozona Counties, Texas are air or gas drilled. Most of the wells are fracture treated using the ball sealer multistage and gelled water technique or a gelled weak acid and limited entry. CO2 is used in many of the gelled acid treatments which include non-emulsifiers, iron stabilizers and KCL to prevent clay swelling.
Most of the Morrow Sand wells of eastern New Mexico are drilled with very low water loss muds, drill stem tested and then cemented with low water loss cement using KCL in the water to prevent cement filtrage damage to the formation. The most common method of perforating is through tubing with a differential into the wellbore. Some wells are completed natural but most respond to a small acid "clean-up" treatment. Data from a study of field results are included in the paper. Many of the completion problems paper. Many of the completion problems attributed to formation damage were due to poorly developed porosity and permeability poorly developed porosity and permeability often associated with edge wells. This means well cost could be substantially reduced by re-evaluating the mud, casing, tubing and stimulation programs.
The Influence of Induced Vertical Fractures on Overall Reservoir Performance
Authors: Williams James L. 
Published: December 2007

Abstract
The purpose of this work was to determine the effects of induced fractures on overall reservoir performance during primary as well as secondary performance. The ultimate objective of this continuing study is to optimize ultimate recovery from tight carbonate reservoirs in which high pressure water injection is the only economically feasible secondary recovery technique.
The influence of fractures on secondary performance has been emphasized in much of performance has been emphasized in much of the industry literature. This report emphasizes that inflow performance data on individual wells can be used to determine the presence of waterflood-induced fractures. presence of waterflood-induced fractures. This documentation is limited to qualitative case studies of two Clearfork reservoirs situated on the Central Basin Platform in West Texas (see Exhibit I). The Platform in West Texas (see Exhibit I). The Monohans Clearfork Waterflood is a one hundred percent Shell-operated project located in Ward percent Shell-operated project located in Ward and Winkler Counties, Texas. The TXL North 5600'/Tubb Unit is a Shell-operated waterflood project located in Ector County, Texas. Both project located in Ector County, Texas. Both projects are in tight, poorly-developed, projects are in tight, poorly-developed, heterogeneous dolomite reservoirs which fracture vertically.
The most significant conclusion reached from this study is that the azimuthal orientation of induced vertical fractures greatly influences the primary as well as secondary performance of tight, discontinuous carbonate performance of tight, discontinuous carbonate reservoirs. A secondary inference is that induced fractures in the Clearfork reservoirs on the Central Basin Platform are oriented normal to structural trend.

DESCRIPTION OF WORK
This report consists of retrospective analyses of the aforementioned carbonate reservoirs where waterflooding is currently being used to enhance ultimate recovery. Azimuthal orientation of induced fractures in the Monohans Clearfork and TXL North 5600'/Tubb reservoirs were determined empirically.
A Review of the Willard (San Andres) Unit CO2 Injection Project
Authors: Johnston J.W. 
Published: December 2007

Abstract
The Willard Unit is located in the Wasson (San Andres) Field in Yoakum County, Texas. The reservoir is a layered dolomite with an average porosity of 8.5 percent and average permeability porosity of 8.5 percent and average permeability of 1.5 md. Secondary recovery by waterflooding has been in progress since 1965. Although secondary operations have been quite successful in the Willard Unit, a substantial amount of oil will be unrecoverable by waterflooding. CO2 miscible displacement project was conducted in the unit to investigate the applicability of this process for full scale improved oil recovery.
The project consisted of two separate field tests to study the various operational and reservoir aspects of the CO2 miscible process. The first of these consisted of eight adjacent CO2 injection wells on regular waterflood spacing. Since this was the first effort to conduct a CO2 miscible flood in this unit, this test was called Phase I. Water and CO2 were injected alternately Phase I. Water and CO2 were injected alternately in Phase I from November, 1972, to February 1975. This area was planned to provide insight into the extent of reservoir sweep problems that might occur in a regular size pattern CO2 flood. It would also provide an opportunity to investigate control measures if these problems arose. Additionally, information would be obtained on injection performance and operational procedures that could be used in planning a unit-wide flood. The second test was located and operated separately from Phase I and was called the Pilot. It consisted of four wells: an injector, logging observation well, pressure observation and sampling well, and pressure core well, all on close spacing. The Pilot was designed to allow a more detailed investigation of the reservoir flow behavior of CO2 and water and to determine the reduction in waterflood residual oil levels due to CO2 injection.
Phase I injection performance was good. The reservoir pressure was maintained above the minimum required for miscible displacement. Cumulative CO2 injection was 3.8 BCF of CO2, or 4.4% of the hydrocarbon pore volume.
Corrosion and Operational Problems, CO2 Project, Sacroc Unit
Authors: Newton L.E. , McClay R.A. 
Published: December 2007

Abstract
The SACROC CO2 Injection Project was initiated following a comprehensive literature search and extensive laboratory investigations to establish system design criteria, select suitable materials of construction, and prepare for operational difficulties that prepare for operational difficulties that might occur. Packing of the CO2 Supply Line at the El Paso Puckett Plant was started in November 1971 and CO2 injection commenced in three SACROC Unit wells on January 20, 1972. This is an alternating water-CO2 project and all wells were placed on prewater injection prior to receiving the first slug of CO2. prior to receiving the first slug of CO2.System performance to date is considered satisfactory; however, some operational problems have occurred. One operating problem has problems have occurred. One operating problem has been corrosion. Corrosion has been minimal in the dry CO2 portion of the injection system and maximum in meter runs, wellheads and tubing which are subject to alternating water-CO2 slugs. The SACROC produced water is considered to be the greatest contributor to this area of maximum corrosion. Corrosion in the producing wells and surface equipment due to return of CO2 has ranged from minimal to severe. Predictions of corrosivity based on CO2 and water cuts have not always proved accruate. Although a few failures have occurred, equipment selection and inhibitor applications have adequately controlled corrosion in CO2 Removal and Reinjection Facilities. Scale and emulsion problems have occurred in isolated instances problems have occurred in isolated instances but thus far have not posed a general problem due to proper treating and handling techniques.

Introduction
The SACROC CO2 flood project was initiated following numerous studies implemented to investigate possible means of increasing the efficiency of the centerline waterflood. Laboratory simulations and engineering calculations indicated that a water driven carbon dioxide flood would yield the highest increased recovery rate and was the most economically attractive. Accordingly, plans were initiated in 1969 to develop a CO2 flood project. Design studies for the field CO2 delivery and injection system were initiated and possible sources for the required large volumes of CO2 were investigated. In December of 1969, the Texas Railroad Commission approved the proposed flood.
Triple Wellhead Technology in Sarawak Operations
Authors: Tuah Joroji B. , Mat M. Rujhan B. , Nam Low Far 
Published: December 2007

Abstract
There are substantial remaining reserves in most of the matured fields offshore Sarawak. Additional wells are required to access those reserves. However, in most cases there are limited remaining well slots available on the existing platforms to drill the new wells. Putting in new structures is costly and often renders the revisit projects uneconomic.
After successful implementation of the Twin Wellhead Technology in its Tukau (ref. 1) and Baram fields, PETRONAS Carigali Sdn. Bhd. (PCSB), has taken a quantum leap in its pursuit for application of innovative new technology. This time it is the implementation of Triple Wellhead Technology in the Bokor field, allows 3 independent wells with 6 production strings to be drilled through 1 shared conductor. This is the first such installation in the world, and significant reduction in project cost has been achieved through reduction in additional conductors to be installed.
This paper presents the development and the application of this new technology. The mechanics and methodology of the wellhead system are briefly explained. The design considerations, the actual project execution and some lessons learned from the project are also addressed.
Reservoir Description of the Mid to Late Jurassic Laminaria Formation: Laminaria/Corallina Area, Timor Sea
Authors: Barr Duncan 
Published: December 2007

Abstract
Woodside Energy Ltd. and their Joint Venture Partners recently contracted Core Laboratories to carry out a sedimentological study on the Middle to Late Jurassic succession in the AC / P8 permit, Timor Sea. The aim of the study was to provide insight into the areal distribution of reservoir facies through examination of the reservoir's vertical stacking patterns, expressed in core from key wells in the region. Particular emphasis was placed on thinly bedded sands at the top of the Laminaria Formation, which appeared to exhibit poor reservoir potential based on wireline log analysis.
The study included data from a total of twelve wells, nine with core, all with complete suites of wireline log data. Conventional description of sedimentary bedforms from core was integrated with ichno fabrics, routine core analysis, wireline log data and high-resolution biostratigraphy to provide a detailed understanding of major correlation surfaces and vertical stacking patterns. This hierarchy of bedding surfaces and associated genetic packages of sediment were then utilised to assess the continuity of sands across the reservoir. Subsequent dynamic simulation modeling based on this work has resulted in a significant increase in estimates of ultimate recovery factor from existing completions. The study will serve as a platform for future geological and petrophysical modeling of the Laminaria Formation.
"Snowbank" Drilling in the Delaware Basin of West Texas
Authors: West Earl Ray 
Published: December 2007

Abstract
Deep wells drilled in the past 2 years have resulted in record penetration rates and/or best bit records for several drilling areas of the Delaware Basin. The West Texas counties involved are shown on the Delaware Basin map, Fig. 1.
The drilling time and bit records for these wells are some of the best in the industry. These wells have been described as drilling like they were in a "snowbank". Actually, the wells are the result of proper planning and good well supervision. A study of deep drilling practices shows that the same operators using practices shows that the same operators using good methods of planning and execution consistently drill better, more economical holes regardless of the drilling area.
The records have been set by using good preliminary planning and excellent well preliminary planning and excellent well supervision. The use of the new journal bearing button bits, low solids nondispersed fresh-water muds and innovative drilling technology has contributed greatly to the success. Careful control of low-gravity drilled solids was practiced in maintaining the mud systems, where practiced in maintaining the mud systems, where feasible clear water was used for the drilling fluid.
A good corrosion-control program combined with a drillpipe inspection program has minimized drillpipe failure.
Completed well costs for the 21,000-plus-ft wells were $2.25 to $2.50 million. Offset wells averaged $2.5 to $3.5 million or more.

Introduction
When a fast, economical well is drilled, the operator nearly always hears a certain amount of conversation that goes something like this: "That well drilled like it was in a snowbank. It's a lot softer over there. Just wait until they drill over here where it's hard."
These comments are often made when two wells are direct offsets. The success of the faster well is usually attributed to luck or soft formations. Rarely is credit given to the fact that the hole was well planned and properly supervised. properly supervised. In the past 2 years, several deep Delaware Basin wells have been drilled in record time with a record number of bits used. (See Table 1.) These wells are some of the best in the industry. The mud costs are low.
Numerical Modelling of Capillary Transition Zones
Authors: Eigestad Geir Terje , Larsen Johne Alex 
Published: December 2007

AbstractFor a large number of reservoirs, a vertical transition zone between water and oil exists. In this zone, both water saturation and capillary pressure vary with height. Traditionally one assumes that there is a relation between capillary pressure and water saturation, given by a Pc-S primary drainage curve prior to any production in the reservoir. The vertical fluid distribution is found by assuming equilibrium between capillary forces and gravity.This paper will focus on numerical modelling of the fluid distribution as production is started in a reservoir. As wells may be open and shut during the (field) lifetime of a reservoir, both imbibition and drainage may occur in different parts of a reservoir. The numerical model will take into account the irreversibility of imbibition and drainage, commonly known as hysteresis, which applies for both capillary pressure and relative permeability.Our test examples will deal with three different production rate regimes; capillary-dominated, capillary-viscous and viscous. We investigate the fluid distribution in the transition zones as the wells are shut down and equilibrium again is reached for the different cases. The tests will show that the fluid distribution differs for different injection-and production rates. For the case where the production in the reservoir is very close to equilibrium, we also show how the fluid distribution can be found analytically.
Integrated Stimulation Applications and Best Practices for Optimizing Reservoir Development Through Horizontal Wells
Authors: Manrique J. F. , Husen A. , Gupta S. C. , Raju A. V. 
Published: December 2007

Abstract
This paper discusses and summarizes technology innovations and practical application of Integrated Stimulation Applications: Matrix Acidizing, Acid Fracturing, Proppant Fracturing and Water Conformance/Control are discussed with an emphasis on horizontal wells applications.
Field case histories are presented to illustrate our approach to develop best practices for optimum reservoir completion through the use of practical and feasible completion methods. Damage characterization for vertical and horizontal wells. Mechanical and chemical diversion techniques (for proper coverage and acid system distribution along pay zone), specific fluid systems to minimize influx of acid into water bearing zones, retarded acid systems for high temperature applications (that enables deeper live acid penetration) are also discussed.
Analysis of the production data is intensively and extensively used to match past performance, forecast production and quantify estimates of reservoir potential and deliverability. Nodal™ system analysis, advanced well diagnostic procedures and numerical reservoir simulation (for complex cases provide means for accurately assessment of reservoir potential and deliverability. The results provide critical input in the decision making process for optimization of reservoir completions, and conform a practical strategy for reservoir management and development.
The process is applicable to a continuously evolving reservoir development strategy that aims at improving well/field economics, productivity and recovery efficiency in new, existent, and re-development field strategies and for small/marginal fields or fast tracking reservoir development.
The approach benchmarks currently achieved production and compares it against optimum achievable production (within practical and economical limits) and utilizes cost effective - Integrated Stimulation Applications (Solutions) that address reserves otherwise left behind.