bluuebunny/crossref_metadata_2025 huggingface dataset:
Real-Time Control of Low-Polymer Fracturing Fluids
Authors: Harris Phillip C. , Walters Harold
Published: December 2007

Productivity gains experienced with low-polymer-concentration fracturing fluids are real. When less polymer is injected into the formation, less polymer residue remains in the proppant pack to cause damage. The 15- to 25-lbm/Mgal polymer concentration fluids now being used have been optimized to produce viscosities similar to the 30- to 40-lbm/Mgal fracturing fluids of the previous generation.

Optimization is a laborious, but straightforward process with a traditional couette-type viscometer. Selected polymer-crosslinker combinations are tested to find the highest viscosity possible for the group as a function of preconditioning shear rate, temperature range, pH, ionic strength, gel stabilizer, gel breaker, surfactant, and proppant type. As each variable is optimized, its effect on the other variables must be examined to ensure the consistency of the data. If the data are consistent, mathematical modeling can be performed. Good computer models allow the practicing engineer to determine the chemical composition of a fluid required for producing a specific viscosity at a given time and temperature.

The second requirement for real-time control is knowledge of the fluid temperature in the wellbore and fracture as a function of the pumping schedule (i.e., rate, volume, distance, etc.). Computer design programs can generate a pumping schedule that is ramped between chemical and proppant stages, or at least to a much larger number than the three or four stages typically used for older-generation designs. For true real-time implementation, field-scale equipment must also be able to implement the pumping schedule seamlessly.

For well productivity, only chemicals required for the specific fluid segment should be pumped, without any excess. Pumping a truly optimized fluid means that the treatment is always on the edge of its performance capabilities. This paper will document the multiple effects of fluid composition on optimized viscosity, and quantify the effects on proppant transport for treatments performed at temperatures up to 300°F.
An Improved Steerable System: Working Principles, Modeling, and Testing
Authors: Gaynor Tom , Chen David C-K , Maranuk Chris , Pruitt Jack
Published: December 2007

A new steerable motor assembly has been designed that provides significant advantages over conventional steerable motor assemblies. The new system, SlickBore™, is comprised of a uniquely designed pin-down mud motor with a specially designed long-gauge PDC bit in a matched drilling system. By treating the bit and motor as a system, it has been possible to overcome the directional limitations previously experienced when long-gauge bits, or short-gauge bits with piggyback stabilization, were used in combination with conventional motors.

This paper describes the new system, its key working principles, and the drilling tests and computer modeling used to confirm the initial design concepts. The paper will also highlight selected field results from more than 100 runs made to date. The field results have not only proven the working principles but also demonstrated its advantages over the conventional steerable systems. The benefits include increased ROP, improved hole quality with less hole spiraling and thus less tortuosity, reduced vibration, lower torque and drag, better steerability, better hole cleaning, increased bit life, and improved PDM and MWD reliability.
The Scratch Test: An Attractive Technique for Determining Strength and Elastic Properties of Sedimentary Rocks
Authors: Schei G. , Fjær E. , Detournay E. , Kenter C. J. , Fuh G. F. , Zausa F.
Published: December 2007

The Scratch Test is a relatively new technique for determination of mechanical properties of rocks. In a Scratch Test, the surface of the rock is scratched at constant depth (typically less than 1 mm) by a sharp cutter, while the applied forces are being monitored. It is found that these forces are closely related to the mechanical properties of the rock. The Scratch Test thus represents a direct measure on the core material, and provides continuous coverage of data for the entire length of available core material.

The work reported here is a detailed study of the Scratch Test as a technique for determining strength and elastic properties of sedimentary rocks. The work is based on extensive laboratory testing of many sedimentary rocks with different mechanical properties. The results of the study show that parameters obtained in a Scratch Test, in particular the Specific Energy, correlate very well with the Uniaxial Compressive Strength (UCS). The accuracy of the Scratch Test for rock strength determination is seen to be at least comparable to the accuracy of the UCS Test, while the resolution is even better. It is also found that the Scratch Test may be used to determine the elastic modulus of rocks with good precision. The Scratch Test only requires access to a free surface of the rock. Hence, it may be run on most available core material. Provided that the core is in a reasonably good shape, no special preparation is required for the test, which is thus both quick and cheap. Unlike the UCS Test, the Scratch Test is almost non-destructive, and provides continuous data coverage. The Scratch Test is therefore a very attractive method for determination of stiffness and strength of core materials when addressing issues like reservoir compaction, hydraulic fracturing, borehole stability and sand production, offering a better resolution and data coverage than any other technique available today. Rock mechanical parameters derived from wire-line log data are continuous but have the disadvantage of being derived indirectly from other measurements, such as sonic velocity, density and porosity.
Determining the Effect of Geological and Geomechanical Parameters on Reservoir Stress path through Numerical Simulation
Authors: Khan M. , Teufel Lawrence W. , Zheng Ziqiong
Published: December 2007

Knowledge of the stress path (ratio of the change of effective horizontal stress to the change of effective vertical stress due to the reservoir pore pressure drawdown) that reservoir rock will follow during production and its effect on reservoir properties are critical for reservoir management decisions to maximize productivity. However, in-situ stress measurements needed to determine reservoir stress path are difficult and expensive to conduct, and the measurement may take several years to collect. In situ stress measurements in carbonate and clastic reservoirs indicate that the reservoir stress path is not isotropic loading (equal to 1.0) and can range from 0.14 to 0.761–2. In the laboratory usually reservoir stress path is calculated using uniaxial strain condition. The calculated uniaxial strain stress path can be significantly different from the measured stress path (Table 1).

This paper presents a finite element numerical model to predict the reservoir stress path due to the reservoir drawdown. The model incorporates essential geologic and geomechanical factors that may control reservoir stress path during production. The effect of size and geometry of the reservoir, contrasts in elastic properties between the reservoir and the bounding formations rock, transverse isotropy in elastic properties, plasticity, far-field boundary conditions, anisotropy in the reservoir initial stress states and stratigraphy and structure of the reservoir was studied. For isotropic reservoir properties, stress path becomes lower as the aspect ratio of length to thickness increase. Lenticular sandstone reservoirs have a higher stress path than blanket sandstone reservoirs that are continuous across the basin. Transverse isotropy with lower vertical elasticity than horizontal of reservoir rock increases the stress path, compared to isotropic conditions. Plasticity of the reservoir rock decreases the stress path significantly at the lower aspect ratio of reservoir, but increases with the increase of aspect ratio. However, plasticity of the bounding formations reverses the process.

Validation of the simulated results was done by simulating and matching the stress path of an existing reservoir. Reservoir initial conditions were obtained from published literature2 and considering that initial conditions simulated reservoir stress path was matched with the actual field measurements by adjusting the magnitude and orientation of the geological and geomechanical parameters.
A Three-Layer Modeling for Cuttings Transport with Coiled Tubing Horizontal Drilling
Authors: Cho Hyun , Shah Subhash N. , Osisanya Samuel O.
Published: December 2007

A new approach of three-layer flow of two-phase (solid-liquid) fluid in annulus, i.e. a stationary bed of drilled cuttings at bottom; a moving bed layer above it; and a heterogeneous suspension layer at the top, is proposed to predict and interpret the cuttings transport mechanism. This new mathematical model is presented to overcome the limitation in the existing two-layer models. This enables efficient prediction of cuttings transport during horizontal drilling using coiled tubing. In particular, the model described in this paper formulates transport process and includes the relevant parameters such as rheological characteristics of the drilling fluid, cuttings size/sphericity/ concentration, wellbore geometry, eccentricity of the coiled tubing, and pumping rate of the drilling fluid.

This paper presents the model development, solution, and simulation of the cutting transport process to illustrate the steps involved in determining the effect of each parameter during the drilling operation. Graphical charts and developed correlations between annular flow rate, rheology, wellbore geometry, eccentricity, cuttings size and concentration in each layer, and the carrying capacity are also presented. The simulation results show how to obtain a reasonable pumping velocity of drilling fluid with the possible lowest pressure gradient that might serve as an operational guideline during drilling. Furthermore, the effects of parameters affecting the efficiency of cutting transport are discussed. These results are compared with published experimental data. The observed agreement and discrepancies are discussed, and further improvements on the current model are proposed.
Maximizing Profitability in Reservoirs Using New Technologies For Continuous Downhole Pressure Systems
Authors: Buchwalter James L. , Calvert Ray E. , McKay Colin S. , Thompson Stephen J.
Published: December 2007

Continuous down hole data in conjunction with new reservoir analysis tools made to work with this data have the potential to revolutionize the accuracy of reservoir management. The economic value of continuous down hole pressure data and the array of available options justify the use of these systems in almost all petroleum reservoir developments. The greatest value of these gauges is that with new data analysis tools reservoirs can be accurately managed early in the producing life, thus optimizing both short and long term reservoir management strategies.

Traditionally, the value of these systems has been for completion optimization using a small subset of downhole data. The full value of the complete data stream has been ignored due to the large volumes of data, and the lack of software systems for efficiently working with these data. Consequently the reservoir has not been fully understood.

A system of software tools has been developed to capture the full value of the data from permanent down hole gauges. This new software system automates the filtering of these data in an intelligent fashion. The resulting filtered pressure data can then input into a variety of reservoir analysis tools, for example reservoir simulation programs can now have a continuous reservoir simulation. Reservoir and production engineers can always have the optimal production strategy for the reservoir based on the current data.

These tools are very easy to use, so models can be developed quickly and continually maintained with minimal effort.

Typically it takes less than a week to build the initial model, and only a few hours a month to update and maintain an accurate history match.

The paper will include a brief review of the down hole technologies and the software system which makes the data accessible to reservoir simulation and other reservoir analysis tools. Applications for the filtered data in both Gulf of Mexico and North Sea reservoirs will be introduced.
Geostatistical Inversion of 3D Seismic Data to Extrapolate Wireline Petrophysical Variables Laterally Away From the Well
Authors: Grijalba-Cuenca Alvaro , Torres-Verdín Carlos , van der Made Pieter
Published: December 2007

Interpretation of well-log data into petrophysical variables, such as effective porosity, permeability, and effective fluid saturation, provides an initial assessment of commercial hydrocarbon assets in the near vicinity of a well. A more accurate assessment requires quantitative indication of lateral continuity away from the well. Because wireline tools can only sense rock formation properties a few meters away from the well, assessment of lateral continuity is at best done qualitatively with the aid of stratigraphie analysis or well-to-well correlations. Seldom do these extrapolation methods take advantage of the nowadays commonly available 3D seismic data. In effect, despite possessing much less vertical resolution than well-log data, 3D seismic data have good lateral resolution that can naturally complement the vertical resolution of well-log data. We have developed an estimation procedure whereby wireline data can be extrapolated away from existing wells using geostatistical inversion of post-stack 3D seismic data. This procedure works by estimating a joint probability density function (PDF) that defines a physical relationship between seismic measurements (e.g. P-wave velocity, and P-wave acoustic impedance), and petrophysical variables (e.g. density/porosity and bed thickness) rendered by well-log data. The estimated joint PDF is further normalized to reflect a vertical resolution midway between the resolution of seismic data and the resolution of well-log data. Variograms are also estimated from well-log and seismic data that define the expected degree of lateral smoothness away from the well. We then generate stochastic realizations of petrophysical variables that not only honor the well-log data, but most importantly, that fully honor the 3D seismic data in a least-squares sense. In the presence of closely spaced wells, geostatistical inversion can also be used to estimate an accurate static reservoir model for the subsequent simulation and planning of in-fìll drilling and/or enhanced-oil-recovery operations. Examples are described in which geostatistical inversion provides lateral delineations of sand units consistent with measured fluid production data.
World Oil: Challenges and Opportunities
Authors: Safer Arnold E.
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

Many observers are of the opinion that OPEC's dominance of the world oil market will last into the next decade. It is more likely, however, that economic forces will gradually re store a more equitable balance between producing and consuming nations and that the natural friction within OPEC itself will limit the cartel's power. U.S. international oil policy should recognize the likelihood of such a development.

Introduction

The purpose of this paper is to suggest an alternative point of view regarding the price of oil. The conventional wisdom today is that OPEC's near-monopoly control of the world's oil markets will last well into the 1980s, if not beyond. We challenge this point of view and suggest that a more probable outcome will be a gradual erosion of the cartel's position over the next few years. We do not foresee OPEC falling apart with earthshaking events of the sort that occurred when the cartel burst onto the world scene in late 1973 in the wake of war, an oil embargo, and quadrupled prices. Rather, we believe that natural economic forces will gradually work toward a reassertion of the market power of the oil-consuming nations between now power of the oil-consuming nations between now and 1980.

The policies devised by the U.S. and other Western governments to take advantage of this market shift will in large part determine the future viability of the cartel. Serious political considerations may suggest that the core Mideastern nations of OPEC may be vital to the security of the Free World, and that attempts to combat the cartel on purely economic grounds might well be contrary to our international political interests. While it is beyond the scope of this analysis to challenge that position on political grounds, we would suggest that the ability of the cartel to impose monopoly prices on the world's oil markets is an equally serious consideration on economic grounds.

The world has not really adapted to the price of international oil maintained by the strength of the oil cartel. The mounting international debt of many developing countries and of some industrialized nations is one important symptom of the disruptive nature of high oil prices. As long as large OPEC surpluses continue, there will be an ever-increasing burden of deficits in the oil-importing nations which must be financed through the international monetary system.
The Need for Dynamic Forecasting of Recoverable Reserves
Authors: Stout John L.
Published: December 2007

THIS PAPER IS SUBJECT TO CORRECTION

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

Estimates of hydrocarbon reserves have been in demand over the past thirty years. Examples follow to illustrate the necessity to try all approaches and effectively correct each prediction through use of newly acquired facts. All available details should be accurately compiled until calculated details are generated.

Methods of geologic basin analysis are discussed based on periodic re-evaluations of new field discoveries mad past performance of producing fields. Each basin's economic profile is determined by the rate of exploratory drilling and the ratio of remaining reserves to current production.

Although the U. S. to date has produced nearly one-third of the world's crude oil, our world economic position is being challenged more frequently and our ability to reliably forecast our remaining recoverable reserves assumes new importance with each challenge.

Introduction

Remaining hydrocarbon reserves in the U. S. are becoming increasingly important to the nation's economic and political future. A new pattern of exploration economics is now developing which indicates new drilling patterns and more efficient recovery. An increased price-cost ratio will immediately expand estimates of undiscovered recoverable resources and, at some threshold level recovery percentages for discovered petroleum will improve. Economists can readily see the effects of increased price-cost ratios that have developed since the 1973 embargo. The question now is "what will be the effect of the next world embargo?" The following statement by Frank G. Zarb outlining national objectives was read before a 1975 Senate hearing on "The Economic Impact of President Ford's Energy Program":
Subsurface Safety Valves for Gas Storage Wells
Authors: Gant Guy W.
Published: December 2007

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

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

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

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

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

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

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

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

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

For 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

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.
Lookback on Performance of 50 Horizontal Wells Targeting Thin Oil Columns, Mahakam Delta, East Kalimantan
Authors: Vo D. T. , Waryan Sukerim , Dharmawan Agung , Susilo Rusdi , Wicaksana Renas
Published: December 2007

This paper presents a case study to look back on the performance of over 50 horizontal wells recently drilled in three different fields in the Mahakam Delta, offshore East Kalimantan, Indonesia. The common application of these horizontal wells is to produce thin oil bands sandwiched between gas cap and bottom/edge aquifer. The objective of the study is to provide lessons learned from the actual well performance data for improving future well planning as horizontal wells continue to be used in these fields.

Based on well performance data, the lookback is mainly focused on the reservoir evaluation aspect of these horizontal wells. Reservoir and well performance is analyzed using a variety of techniques, varying from single-well analytical modeling (or decline curves) to more complex reservoir simulation. Based on statistical data resulted from the analysis of these wells, specific relations between reserves and reservoir-well parameters are identified which will be useful for predicting future well performance, especially during early prognosis. Practical issues related to well planning such as selection of well location, well length, well path, and standoffs to fluid contacts are presented. The paper also discusses specific operational strategy used in drilling, completing, and producing these horizontal wells.

Results from the lookback provide guidelines and refinements for our continuing implementation of horizontal wells to optimize thin-oil-column development in these fields.
Real-Time Rig Information System Promotes Operational Efficiencies in Drilling the Greater Ekofisk Area
Authors: Oberkircher Jim , Herbert Mike , Talkington Kelly
Published: December 2007

Fast, reliable information is critical in today's fast paced drilling operations where the time value of decisions can be very high. The need for a system to provide real-time data directly from the rig site of remote and offshore locations to the personal computers of the decision-makers in various locations at the same time has never been greater. Philllips Petroleum Company of Norway (PPCoN) and Sperry-Sun have embarked upon the implementation of just such a system within the Greater Ekofisk area of the North Sea with great results.

The use of the INSITE System, with its low-cost, advanced communications and networking capabilities, on the PPCoN operated wells, particularly those classified as HTHP, has enhanced the operator's ability to make quicker, more informed decisions. It has stretched the technical resource base by putting the critical information at the users' fingertips, including information not normally captured or transmitted from the rig. The use of INSITE has contributed to reduced well costs by allowing better and more informed decisions and by allowing qualified personnel to monitor operations on more than one rig at time from the office.

This paper will examine how the system was implemented and used and will discuss some of the operational and cost savings benefits.
Implementation of Hydraulic Fracturing to Improve Oil Production and to Solve Sand Problem (Case Study: Kenali Asam Field)
Authors: Hadi Gunung Sardjono , Arifin M. Ainul
Published: December 2007

There are many kinds of methods to improve oil production such as production optimization, implementing of enhanced oil recovery, horizontal drilling, etc. It's depending on the reservoir characteristics. For example, changing pump size with the big one is not always to get a good result particularly in the reservoir that has sand problem. Acidizing treatment is also sometimes successful and failed. In order to get the best solution, a hydraulic fracturing is one of many alternatives to handle sand problem and also could improve the production at the Kenali Asam field.

Kenali Asam field is located approximately 7 Km South of Jambi City, South Sumatra, Indonesia. Since the field was found in 1931, has drilled 260 wells with 19 layers in Air Benakat Formation group.

Hydraulic fracturing has implemented since 4 years ago in this field, particularly in layers d/320, b/400, P/1050, and S/1170. The best result is obtained from sand b/400 (shallow sands). The most problem in these layers one of them were tight (the permeability is less than 20 md) and another layer has a good permeability (more than 200 md), but unfortunately has sand problem.

Using hydraulic fracturing the production could be increased significantly and some of them also could solve the sand problem. For instance, from sand d/400 has been giving the gain around 1.170 barrel per day. And, from economical side this job still attractive due to the total cost of hyfract job (including rig cost) is still less than US $ 100,000 per well. Due to sand b/400 is very potential and attractive, in this paper, the focus discussion about sand b/400 and also will discuss about the kind of suitable proppant for this reservoir.