bluuebunny/crossref_metadata_2025 huggingface dataset:
Water-Based Formation Imaging and Resistivity Logging in Oil-Based Drilling Fluids-Today’s Reality
Authors: Laastad H. , Haukefaer E. , Young S. , Tehrani A. , Delaunay P. , Feather K. , Phillips J. , Marca S.
Published: December 2007

Historically, acquiring borehole image logs and resistivity at the bit measurements of useable resolution have been difficult, if not impossible, when using oil-based drilling fluids. Conversely, in many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, which deliver logs of higher resolution.

Azimuthal borehole images in oil-based mud systems are delivered by wireline conveyed ultrasonic measurements or azimuthal density measurements made while drilling. Higher resolution images have generally been out of reach in oil-based systems because the measurement technology used to deliver these services involves passing electric current through a conductive borehole fluid.

Resistivity-at-bit devices used for geostopping and geosteering also rely on electric current transmission from the bit to the formation and are optimized for a conductive mud system. In many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, thus placing high-resolution images, resistivity-at-the-bit, and the high-value applications that these services can deliver out of reach of the reservoir evaluation and well placement teams.

This paper describes the development and successful application of a conductive oil-based drilling fluid system that produces water-based logging quality and enhanced geosteering without sacrificing the performance advantages of invert-emulsion fluids. This unique system, employs an electrically conductive continuous phase that provides a high-performance fluid with a conductive mud, filter-cake and filtrate. The authors detail the development of the system, which included a yard test where fluids of varying conductivity were circulated through a test well with formation micro imager response determined and compared against measured conductivity.

Further, the authors discuss the application of this new system on the Gullfaks South in the Norwegian sector of the North Sea, where the fluid was used to drill a highly deviated well through complex geological structures. In this application the fluid showed the drilling performance expected from an invert-emulsion oil-based fluid (i.e. high penetration rates, wellbore stability and low torque/drag). Results from formation micro image logs and resistivity-at-bit measurements taken using this fluid are presented and discussed.

The authors also review lessons learned in the development and field application of this conductive fluid, and address current limitations and future developments.
Multivariate Statistical Analysis Improves Formation Damage Remediation
Authors: Tague J. R.
Published: December 2007

The design and implementation of remedial techniques used to overcome formation damage can be costly and time-consuming. In formations with multiple formation damage mechanisms, the challenge becomes even greater. In many cases, numerous trials must be conducted to determine the appropriate treatment. Even then, distinguishing the important variables can be difficult. In the past, this has led to suboptimal design and poorly defined candidate selection criteria.1 Fortunately, multivariate statistical analysis can greatly simplify the task. Several useful forms of multivariate statistics include correlation matrices, multiple regression, and experimental design. Correlation matrices can quickly identify variables that are critical to success. Multiple regression can build upon the initial analysis and calculate potential results based on selected variables. Finally, experimental design can be used to reduce the overall number of remedial attempts necessary to determine critical success factors.

This paper will introduce the concept of multivariate statistical analysis and describe the multivariate techniques that can be used to improve formation damage remediation. In addition, actual examples will be presented of multivariate analysis used to improve acid treatments, solvent washes, and several other forms of remediation used in the West Coalinga field – a field known for its multiple formation damage mechanisms. Overall, this paper should provide a solid background for anyone who wishes to use statistical analysis in their efforts to improve formation damage design, treatment, and implementation.
The Dynamics of Electric Submersible Pump Populations and the Implication for Dual ESP Systems
Authors: Sawaryn S. J.
Published: December 2007

This paper contains analytical expressions illustrating the growth, renewal and decline of single Electrical Submersible Pump (ESP) populations and their transition to dual ESP systems. Critical assumptions are justified using published data. The commercial implications of the conclusions are presented. Discussion starts with possible misinterpretations of Instantaneous Run Time, which is a commonly adopted measure of pump reliability. Statistical renewal theory is then used to quantify the sensitivity of workover delay time to rig availability and to determine the expected change in failure rates when replacing an existing pump population with more reliable units. The transition is shown to be relatively insensitive to even large improvements in reliability.

Dual ESPs are considered as a means of improving runlife. When analysed as a stand-by redundant system they are predicted to exhibit a gamma distribution. Under certain conditions, the replacement of an existing pump population with dual ESPs is predicted to result in a faster reduction in the workover rate and confer additional commercial benefits compared to a single ESP with the same mean time to failure (MTTF). The first dual ESP system for the Milne Point Field (MPU), Alaska was successfully run in a Kuparuk well in April 2000.

It is concluded that dual ESP systems deserve greater consideration. The material is of interest to vendors designing ESP systems and those managing fields utilising ESPs, particularly those involved in incentive based contracts.
Using the Cased-hole Formation Tester Tool for Pressure Transient Analysis
Authors: Hurst S. M. , McCoy T. F. , Hows M. P.
Published: December 2007

This paper presents three pressure transient analysis case histories using a wireline cased-hole formation tester (FT) as part of an appraisal program in the Peng Lai 19-3 field, offshore China. A typical cased-hole formation test operation involves perforating a 1-foot interval via wireline, setting the testing tool across the perforations with straddle packers, and pumping formation fluids through the tool to catch representative samples. Although the main goal of the cased-hole wireline formation test program was to obtain fluid samples, short pressure buildups lasting approximately 2 hours or less were also conducted. We found the character of the pressure data and the resulting transient analyses to be comparable to those from cased-hole drillstem tests (DST's).

Wireline formation testers have traditionally been used in open-hole to gather formation pressures and collect fluid samples. On a limited scale, the pressure data have provided information about reservoir properties from pressure transient analysis. However, it is difficult to run these tools in some types of formations (unconsolidated sand, unstable shales) because of collapsing formations, differential sticking, and sand production. The Peng Lai 19-3 Field consists of a series of stacked, unconsolidated sandstone reservoirs having wide variations in oil PVT properties with depth. Using the cased-hole FT tool offers a significant cost saving by reducing the number of drillstem tests required to characterize these stacked reservoirs. This paper will (1) describe the tool setup and procedures used to collect the fluid and pressure data and (2) present the pressure transient analysis of the data using traditional methods (log-log and semi-log techniques).
Triple Frac-Packing in a Ultra-deepwater Subsea Well in Roncador Field, Campos Basin - Maximizing the Production Rate
Authors: Rovina Paulo S. , Pedroso Carlos A. , Coutinho Arthur B. , Neumann Luis F.
Published: December 2007

The key issue to develop the Roncador field, located in ultra deep water offshore Campos Basin, in Brazil, is the maximization of production rate keeping the completion reliability, avoiding premature high workover costs involved in that scenario. Roncador reservoir has a succession of thick turbidite sandstones containing 31° API oil, requiring sand control and water injection to maintain reservoir pressures above saturation’s. The distance between the pay zones are as short as 12 meters, becoming the first problem to fit the gravel assembly in such a short space. Flexibility in the completion is provided by an internal string with sliding sleeves. When water coning occurs in any zone, the sleeves shall be closed using slick line in a light workover.

The paper will describe the main challenges to carry out three stacked frac-packs in a subsea well drilled in water depths above 1800 m, considering the experience acquired from the first three deviated subsea wells, working in dynamic positioned rigs. Special procedures were adopted to prevent failures during the completion, such as: rigid control of fluid cleanness and gel properties, selection and operation of service tools suitable to that environment (heaving, risk of rig drive-off) and careful design for frac-pack based on minifrac data.

The drives for equipment selection will be reviewed, including the choice of perforation charges, gravel equipment and sliding sleeves. The good results obtained in those frac-packs, using the Tip Screen Out technique, reducing the skin effect compared to conventional gravel pack, will be presented too.
Application of 3D Streamline Methodology in the Saladin Reservoir and Other Studies
Authors: Chakravarty A. , Liu D. B. , Meddaugh W. Scott
Published: December 2007

A study of the Saladin (Barrow Group) reservoir (off shore Western Australia) was conducted using the 3D Streamline Simulation (3DSM) in 1998. This reservoir was in a harvest mode and therefore it was deemed important to investigate any remaining potential prior to abandonment. The reservoir has been on production since December 1989 entirely under primary depletion supported by an extensive and strong aquifer. Current recovery factor is over 70%!

The study was initially conducted using a standard finite difference simulator but lengthy run times were encountered. Due to project time constraints a 3DSM model was constructed and tested. This model was found to be stable with significantly shorter run times. A very good history match was achieved in a short time and the results indicated two distinct areas of significant bypassed oil. The history matched model data was then converted into the finite difference model. An almost identical history match solution was achieved quickly but at significantly longer run times.

As a result of this modeling, drilling during mid-1999 in one of the recommended target areas has yielded significant recovery of bypassed oil.

This paper will highlight 3DSM (based on Reference 1) and its applicability to other reservoirs via the Saladin study. Other applications (e.g. geostatistical model screening.) currently being undertaken using this methodology will also be discussed along with comparisons to finite difference simulators. Conclusions will also be presented on the advantages and impact of using this methodology for reservoir studies.
The Application of Stand-alone Injection Systems in Remote and/or Highly Populated Areas Reduces Construction Costs
Authors: Al-Gamber Abdulwafi A. , Al-Towailib Abdulazeem A. , Al-Wabari Saeed H.
Published: December 2007

This paper discusses the successful application of a standalone injection system to provide pressure support for Hanifa reservoir of Abqaiq Field, Saudi Arabia. This stand-alone injection system is a cost-effective method to provide localized powered-water injection for areas inaccessible by pipelines or costly to tie to the centralized injection facilities. Such a system has recently been successfully deployed for developing part of Abqaiq Field overlain by a residential area. The reservoir under development is relatively tight that would not effectively respond to the prevalent simple gravity dump flood, as is the case for the overlaying high-permeability Arab-D reservoir. The system consists of a single well that serves as the water supply and injector in one, and a horizontal pump. The well has a dual completion across a shallow aquifer and the target reservoir. A tubing and packer allows aquifer water to free-flow behind the tubing to a skid-mounted surface horizontal pump, where it is then boosted and injected back through the tubing to the target reservoir. The introduction of this system in a pilot well and two subsequent completions has resulted in significant cost savings versus the conventional tiein to the centralized injection facilities. The construction of a potentially hazardous high-pressure flowlines across the population center has been avoided, while allowing the development of this part of the field, which, otherwise, would require the more expensive extended reach drilling.
Improving Sandstone Matrix Acidizing for Oil Wells by Gas Preconditioning
Authors: Aggour M. A. , Al-Muhareb M. A. , Abu-Khamsin S. A , Al-Majed A. A.
Published: December 2007

Experience has shown that for sandstone formations, oil wells respond to matrix acidizing in a different manner as compared to gas wells. For oil wells, the improvement in permeability resulting from the stimulation treatment peaks at a certain acid volume and then drops as the volume of acid injected increases. For gas wells, however, the resulting improvement in permeability is roughly proportional to the volume of acid injected, and is normally better than that obtained with oil wells. It is, therefore, expected that stimulation of oil wells in sandstone formations could be improved by displacing the oil in the zone to be acidized with gas. Gas injection prior to acidizing is sought to minimize the formation of emulsions or sludges between the spent acid products and the oil that otherwise would be contacted.

This paper presents the results of an experimental investigation on the effect of gas pre-conditioning of the damaged sand on permeability improvement by matrix acidizing. Experiments were conducted on Berea sandstone cores saturated with 29.2 °API crude oil at selected reservoir conditions of 180 °F and 3000 psi pore pressure. Carbon dioxide and nitrogen were separately used for pre-conditioning prior to stimulation and the results were compared against stimulation without gas pre-conditioning.

It was found that with regular stimulation, improvement in permeability peaked at a certain acid volume. With gas (CO2 or N2) pre-conditioning, however, continuous improvement in permeability was obtained with increasing the volume of acid injection. Further, using gas pre-conditioning with a small volume of acid (that would otherwise not be sufficient to even recover the original permeability with regular acidizing) resulted in permeability improvements of up to 200% of the original pre-damage permeability. At an acid volume that would just restore the original permeability with regular stimulation, gas pre-conditioning resulted in permeability improvement close to 300% of the original permeability. Preconditioning with either CO2 or N2 provided superior results compared to regular stimulation. However, CO2 was found to be more effective than N2. This is attributed to the fact that CO2 has better miscibility than N2 and would, therefore, provide more efficient displacement of the oil out of the zone to be stimulated.
Shallow Gas Kick: Simulation and Analysis for Top Hole Drilling Without a Riser
Authors: Marken Craig , Hansen Svein , Øregaard Jakup
Published: December 2007

The influx of a shallow gas kick during top hole drilling operations without a riser can result in critical well control and safety problems for both the drilling rig and personnel. With appropriate well planning tools these top hole challenges and possible corrective actions can be addressed prior to and during these drilling operations. Based on modifications to an existing gas kick simulator package, such a well planning tool has been developed and demonstrated for the simulation and analysis of possible shallow gas kick scenarios.

Although this tool was initially intended for an analysis of the potential for elimination of the pilot hole, the emphasis of this study became the safety limits of the pilot hole itself. The simulations show the threshold levels for uncontrolled blowouts as a function of gas zone formation permeability and gas pressure when using a 9 5/8" pilot hole. A comparison with a larger 17 1/2" hole has demonstrated the lack of shallow gas kick control at the same permeabilities and even lower gas pressures. Dynamic circulation control of a shallow gas kick as a function of time after penetration of the gas zone, irrespective of when a kick is detected, shows the advantages of the pilot hole. However these advantages must be tempered by the realization of a very short reaction time.

The additional hydrostatic pressure resulting from suspended cuttings can make the difference between the control of the shallow gas and uncontrolled kick. After penetrating the gas zone circulating the cuttings out of the annulus to clean the hole can reduce the downhole pressure sufficiently to initiate a blowout while otherwise maintaining the circulation rate that would control the shallow gas.

Although the pilot hole reduces the potential for a shallow gas kick, its presence, even with careful attention to drilling operations and practices, can lead to a false sense of security. This simulator has been a valuable tool for safety analysis and planning of top hole drilling operation where shallow gas zones are a part of the formation prognosis.
Adapting Probabilistic Methods to Conform to Regulatory Guidelines
Authors: Acuña Herman G. , Harrell D. R.
Published: December 2007

Probabilistic methods have introduced inconsistent interpretations of how to apply these methods while complying with reserve certification guidelines. The objective of this paper is to present and discuss some pitfalls commonly encountered in the application of probabilistic methods to evaluate reserves. Several Regulatory Guidelines that should be followed during the generation of recoverable hydrocarbon distributions are discussed. An example also is given to understand the evolution of reserve categories as a function of probabilities.

Most of the conflicting reserve interpretations can be attributed to the current SPE/WPC reserve definitions where reserve categories are expressed in terms of probabilities of being achieved. For example, proved reserves are defined as those hydrocarbon volumes with at least a 90 percent probability of being equaled or exceeded (P-90). Unfortunately, these definitions alone fall short as guidance on how to derive the distributions from which these percentiles will be calculated. A simple example of this problem is the derivation of an exploratory prospect hydrocarbon resource distribution. While a P-90 can be calculated from this distribution, no proved reserves should be assigned to the prospect until it has actually been drilled and proven economical.
A Simple and Accurate Description of Non-Linear Fluid Leak-Off in High-Permeability Fracturing
Authors: van den Hoek P. J.
Published: December 2007

Fluid leak-off in hydraulic fracturing is conventionally described using the well-known linear (Carter) model. Although this works well in low-permeability formations, the linear leak-off assumption may lead to –sometimes significant-overestimation of fracture dimensions in medium to high permeability formations. At present, no methodology is available that allows an easy estimation of the impact of nonlinear fluid leak-off on fracture dimensions and on pressure decline (mini-fracture) analysis. The current paper aims at resolving that deficiency.

An exact numerical solution is presented to the fully transient elliptical fluid flow equation around a propagating hydraulic fracture for arbitrary pump rate(s). In addition, a simple analytical formula for leak-off rate is presented that is shown to yield an excellent approximation of the numerical results, both during fracture growth and after shut-in. This formula can be easily incorporated into any existing hydraulic fracture model, and is applicable over the entire range of fluid leak-off rates, i.e. from low-permeability fracture stimulation on one hand to high-permeability waterflood fracturing on the other hand.

The above result is applied to a variety of hydraulic fracturing field examples to explore the limits of the linear (Carter) leak-off assumption, both in pressure-decline analysis of minifractures and in fracture design. It is, amongst others, shown that in frac-packing and high-perm CRI, the linear leak-off assumption may lead up to a tenfold overestimation of fracture dimensions. This result helps to explain the common field observation that CRI in unconsolidated sandstones results in fractures that appear to be significantly smaller than predicted by conventional hydraulic fracture models.
New Through-Tubing Junction-Isolation System Enables High-Pressure Stimulation in the Ekofisk X-02 North Sea Multilateral Well: Case History
Authors: Steele David J. , Edholm Steinar
Published: December 2007

Phillips Petroleum Company, Norway (PPCoN) operates the Ekofisk and Eldfisk Fields in the North Sea. In an effort to increase production while reducing well costs in these fields, the operator implemented a plan to drill three multilateral wells. The maturing Ekofisk and Eldfisk Fields produce from multiple chalk reservoirs with natural fractures. Drilling horizontal wellbores to intersect the natural fractures within chalk reservoirs has proven to be very successful throughout the world (i.e. North Sea and the Austin Chalk Trend in Texas). Thus, by drilling three multilateral wells, Phillips would not only be able to intersect the reservoirs targeted but also would be able to save three platform slots and reduce the expense of drilling and completing three horizontal wells.

Although this project involved completions of three wells, this paper will focus on the third well, the Phillip’s Ekofisk X-02, which was the most successful because of the lessons learned and applied from the first two completions. The primary changes made in the completion design and operational strategies in the third well relate to junction integrity and the use of a state-of-the-art Straddle Stimulation Tool (SST) to isolate the lateral junction during performance of a high-pressure acid-fracturing operation on the upper lateral. The SST is designed to eliminate complications sometimes encountered with traditional upper lateral stimulations such as when drill stem test (DST) tools or plugs do not inflate or retrieve properly. Additionally, this through-tubing, junction-isolating stimulation tool is less costly and safer to use because the stimulation is conducted after the completion equipment and production tree have been installed.

Comparing the results of the X-02 completion with the first two will illustrate that the capability to perform a high-pressure acid-fracture stimulation (versus a acid-wash stimulation) can increase production and eliminate the risks and costs of running a DST-type acid-fracturing procedure. In addition, since the completion string and production tree can be installed before perforating and stimulating the well, safety is increased, and future well costs can be reduced since the lateral can be re-stimulated without pulling the production string.
Foinaven 4D Seismic - Dynamic Reservoir Parameters and Reservoir Management
Authors: O'Donovan A. R. , Smith S. G. , Kristiansen Pal
Published: December 2007

4D seismic data acquired across a segment of the Foinaven field have been combined with Petrophysical data and reservoir simulation. The resulting integrated, multi-disciplinary approach places 4D seismic data firmly in the arena of reservoir management. As a result of this successful application across a segment of Foinaven, 4D seismic data will be acquired on an annual basis across the two producing fields in the West of Shetland area of the UKCS and contributes significantly to reservoir management.
Strategies for Optimal Enhanced Recovery of Heavy Oil by Thermal Methods, Midway-Sunset Field, Southern San Joaquin Basin, California
Authors: Schamel Steven , Deo Milind
Published: December 2007

A previously idle portion of the Midway-Sunset field, Aera Energy's Pru Fee property, has been brought back into commercial production through tight integration of geologic characterization, geostatistical modeling, reservoir simulation, and petroleum engineering. This property, shut-in over a decade ago as economically marginal using conventional cyclic steaming methods, has a 200–300 foot thick oil column in the Monarch Sand. However, the sand lacks effective steam barriers and has a thick water-saturation zone above the oil-water contact. These factors require an innovative approach to steam flood production design that balances optimal total oil production against economically viable steam-oil ratios and production rates. The methods used in this DOE Class III oil technology demonstration are accessible to most operators in the Midway-Sunset field and could be used to revitalize properties with declining production of heavy oils throughout the region.

The production strategy adopted in the steam flood pilot is to restrict steam injection to the upper one-third of the pay zone, that portion where oil saturations exceed 50%. Any steam injected below this interval would loose large quantities of heat to water and result in unfavorable steam-oil and water-oil ratios. During the fourth year of the oil demonstration project, production from the 8 ac four-pattern steam flood pilot continued to remain high. As of December 1999, the oil rate was averaging 308 BOPD and the cummulative oil production from the pilot alone was 335 MBO. The steam-oil and water-oil ratios, measures of steam flood effectiveness, closed the year at about 5 and 8, respectively. Also, an additional 37 new wells drilled in 1998 surrounding the pilot have been put into cyclic production. By the end of 1999 they were producing up to 458.3 BOPD, bringing the total oil rate for the Pru Fee property up to 689.0 BOPD. The total production from the property since the beginning of the project in late 1995 is 541.0 MBO. The average production rates per well are higher under steam flood than in cyclic mode.
Analytical Solution of Dynamic Inflow Performance
Authors: Asheim H.
Published: December 2007

Due to the compressibility of reservoir fluids and matrix, production wells posess dynamic properties. Analytical solution are developed for inflow performance, when bottom well pressure is subjected to combinations of oscillations and excursions. The formulae provided predict the dynamic productivity index, as function of rock and fluid properties, oscillation frequency and attenuation factor. The dynamic inflow performance provides proper bottom well boundary condition for stability analyses of gas-lifted wells.
Effect Of Underground Waters In Localizing Oil Accumulations
Authors: Dickey Parke A.
Published: December 2007

Oil and gas are fluids but our prospecting methods have been based mainly on observations of the reservoir rocks. Little use has been made of measurements of the physical and chemical properties of their fluid contents.

There is now general agreement that petroleum originates in a very disperse state and is segregated into oil pools during the compaction and lithification of the sediments. The mechanism of this process is little understood, but it may be caused by the expulsion of pore water from the sediments and involve a capillary filtering action. If the routes of water migration and the location of capillary filters could be predicted, much more use could be made of our available geological data in predicting likely places for oil to accumulate.

Usually the oil remains where it was originally trapped. Sometimes, however, the regional dip may be reversed and the oil will then run to the other end of the aquifer that contains it. In mountainous areas, reservoirs are severely disturbed and often breached so the oil can run out, which is the principal cause of surface oil seeps. In such areas an effort should be made to locate the sites of the original accumulations, and then consider where the oil might now be.
Field Study - Ford Geraldine (Delaware Sand) Unit
Authors: Meyers Brent D. , Hagler James A.
Published: December 2007

This paper presents a case history of the Ford Geraldine (Delaware Sand) Unit waterflood operation located in Culberson and Reeves Counties, Texas. The Unit, operated by Continental oil Company, is presently under waterflood in the Delaware presently under waterflood in the Delaware Sand. Presented is a discussion of injection pattern selection, injection well interval pattern selection, injection well interval control and monitoring, injected water quality control and, finally, use of reservoir models in prediction and performance matching.

Extensive water injection well work has been performed consisting of running injection profiles on most wells and remedial jobs on wells with poor injection distribution to alter injection profiles and improve vertical sweep efficiency. Injected water quality control is unique in that Pecos River water is used, which necessitates oxygen and bacteria treating in addition to the removal of solids by filtration. Three computer reservoir simulation model studies have been run to match performance, to date, and to assist in selection of infill well locations.

Specifically, the significance of the Ford Geraldine (Delaware Sand) Unit waterflood is that it is one of the very few successful waterfloods in the Delaware Sand. Field data, lab data, and computer modeling work will be presented in the discussion.

Introduction

The Geraldine-Ford Field is located in extreme northern Reeves and northeastern Culberson Counties, Texas. Refer to Fig. 1. Development began with the discovery by Ford Chapman, of the G. E. Ramsey No. 1, in April 1956, and has continued to date. Production from the Geraldine-Ford Field is from the Bell Canyon Formation of the Delaware Mountain Group at an average depth of 2680 feet. There are two producing Bell Canyon Sand members in this reservoir. The Ramsey, or upper, Zone is the principal producing sand body and the Olds, or lower, Zone has been found to have productive potential throughout a large portion of the potential throughout a large portion of the field. The Ramsey Zone is considered the better waterflood prospect due to its greater areal extent and more favorable porosity, permeability, and oil porosity, permeability, and oil saturation.
Well Logs and 3D Seismic Data Integration Using Geostatistical Methods, Lomas del Cuy Field–Golfo San Jorge Basin–Argentina
Authors: Atencio Mario , Sánchez Victor , Breda Eduardo , Fronza Silvana , Saavedra Benito , Hansen Tomas , Souza Jorge
Published: December 2007

The Estancia San Justo Norte Area in the Lomas del Cuy Field was characterized using geostatistical methods. The distributions and thickness of sand bodies were determined within an area of over 20 square km, with 42 drilled wells, and 3D seismic interpreted by REPSOL-YPF.

The intervals of interest were determined from well logs, correlated throughout the field and related with the 3D seismic data. The appropriate reflectors were identified in the seismic, and time windows were established so that these would match the selected intervals. A total of seven windows was used and within each of them 25 seismic attributes was extracted. On the other side, petrophysical evaluations were made from well logs obtaining results for gross, net and net pay thickness and average petrophysical properties within the intervals.

Good correlations were found between petrophysical properties and certain seismic attributes in 6 of the 7 windows. In these cases, cokriging was used to map the petrophysical properties integrating the seismic data. As a result, petrophysical maps guided by seismic attributes were obtained for net thickness, net/gross, net porosity thickness and average net porosity. These maps proved very useful for determining new well locations.

The results clearly indicate that the application of this technique is very effective for describing the fluvial type reservoirs with small lateral continuity, typical of the Golfo San Jorge Basin. Geostatistical methods were good predictors of sand body distributions in each of the analyzed intervals.

This data is extremely valuable in the development of fields when it is integrated with the rest of the available information in the area.
Fluid Design Considerations for Deep Hot Wells
Authors: Barrett N.D. , Joyce V.A. , Free Dustin
Published: December 2007

Greater depths mean increased temperatures and usually mean increased pressures. These two parameters have dictated changes in the way hydraulic fracturing treatments are designed and performed.

The purpose of this paper is to describe current fracturing fluids and to discuss their advantages, shortcomings and applications. A singular, ideal frac fluid does not exist since requirements will vary with the formation, well conditions, fracture design, economics and stimulation goals. However, basic principles can be staged as a guide to a more optimum fluid for high temperature requirements.

Introduction

The search for energy has led to deeper and deeper drilling. Where just a decade ago a 10,000-ft. well and its associated temperature stretched the limits of our treatment fluid technology, it is now commonplace to design and perform hydraulic fracturing treatments at depths below 15,000 feet. Successful fracture acidizing treatments have been performed in wells whose depth exceeds 24,000 feet. Temperature at these depths ranges from 250 degrees F to 400 degrees F in the Anadarko Basin.

Bottom-hole static temperatures of wells in the Anadarko Basin can usually be defined by a temperature gradient of 1.0 to 1.2 degrees Fahrenheight per 100 feet of depth. This is the area in which the authors are most familiar. Using this temperature gradient criteria, a 16,000-ft. Morrow formation well drilled in an area having a 1.1 degrees F/100 feet gradient will have a BHST of 250 degrees F.

Electric logs are relied upon to measure the temperature of each individual well.

FLUID DESCRIPTIONS

1. Water Gels

Water gels can be easily mixed by batchor continuous mix processes with goodreliability and can be made temperaturestable. Surface pressures are less than with other fluids. This results from high hydrostatic heat and friction pressures that are only 25% to 35% offriction pressure of water alone.
Advanced Dual Probe Formation Tester with Transient, Harmonic, and Pulsed Time-Delay Testing Methods Determines Permeability, Skin, and Anisotropy
Authors: Proett Mark A. , Chin Wilson C. , Mandal Batakrishna
Published: December 2007

Three new pressure-transient testing methods are employed to determine horizontal and vertical permeability using a dual probe formation tester. Real-time interpretation during acquisition of pressure data, is the focus of all three new pressure-testing techniques. In the first, a new spherical flow model with anisotropy, storage, and skin is developed from first principles for dual probe analysis. Historically, pressure transient solutions are presented as Laplace transforms and approximated in the time domain using numerical techniques. Typically, early, intermediate and late time periods are identified using derivative plots; but very often, the selection of appropriate data results in confusion. Here, the Laplace transform is inverted to yield a single, exact, closed form, analytical, time domain solution valid for all times, making real-time parameter matching possible with high accuracy.

The second technique uses an oscillatory displacement source at the piston face, and the phase delay of the pressure pulse between the probes is used to determine permeability and anisotropic index. This technique is particularly useful when the second monitoring probe signal is weak (as in high permeability zones) or where there is large spacing between the probes. Pulse timing can usually be detected more accurately than its magnitude, thus extending the range of permeability and anisotropic measurements. This methodology, which is based on a derived relationship between wave phase and permeability, was developed by mathematical analogy with resistivity determination methods used in induction logging.

In the above method, it is often possible to encounter "phase wrapping" for excessively tight formations, leaving an indeterminate permeability. To circumvent this problem, in the third method, a short, abrupt "pulse" having a well-defined "center frequency" is produced at the piston face, and its travel time is measured until arrival at the receiver probes. The harmonic, closed form expression is then used to translate this travel time to permeability. This new method is analogous to sonic wave models; although, of course, "waveforms" are often smeared due to the diffusive nature of the problem.

Simulation results using a detailed finite element, dual probe model are compared against the above analytical methods to assess the effects of near wellbore parameters such as mudcake effectiveness, probe, and packer size. Field-test results are shown to demonstrate the successful implementation of these new testing methods. The three methods described above provide a practical level of redundancy in permeability prediction. Also, monitoring permeability and anisotropy changes while sampling are shown to be beneficial in identifying fluid type changes.
Theory and Application of Well Analysis
Authors: Morgan Rodney , McKee Fount E.
Published: December 2007

FUNDAMENTALS OF WELL ANALYSIS

A well analysis program is an area where any oil company can make money immediately. It appears that most well analyses are performed by large oil companies that have large computer facilities. However, in order to use these facilities, a great deal of effort is required on the part of the engineer or technician. Quite often, the engineer could make a few calculations with a small calculator and have the answer to the problem. This requires that the engineer understand the basic principles of the pump, rod string, and pumping unit operation

Equipment to obtain the necessary data has been hard to use and required considerable time. Usually, the pumping system had severe problems before the time and effort would be spent to analyze it. Now, equipment is available that will allow the engineer or technician to obtain the data easily and make an analysis in a few minutes.

Of primary importance is a thorough understanding of the operation of a modern oil well pump. Fig. 1 is a schematic drawing of such a pump.

There are three main components of an oil well pump: the standing valve (SV), the traveling valve (TV), and the pump barrel. The SV is located in the bottom of the pump barrel and opens or closes, depending on the relationship between the Pressure Pl and P3. The TV is located in the plunger and opens or closes, depending on the relationship of the Pressures P2 and P3. Pressures P2 and P3.The operation of the pump is as follows. Assume that the pump plunger is at its lowest point and is starting to move upward. As the point and is starting to move upward. As the pump plunger stops and begins to move upward, pump plunger stops and begins to move upward, the TV closes because Pressure P2 is the same as Pressure P3, and the weight of the TV causes it to fall into its seat. With the TV closed and moving upward, Pressure P3 is reduced. When the pressure difference between Pl and P3 is large enough, the SV will be forced open. This allows well fluid to flow into the pump barrel. As the plunger rises, the pump barrel continues to fill. Note that the reason for the pump barrel filling was the plunger moving upward, which reduced Pressure P3. When the plunger stops its upward movement at its plunger stops its upward movement at its topmost position, Pressures Pl and P3 equalize and the SV closes because of its own weight. When the plunger, starts down, it will be forced into the fluid in the pump barrel, which will cause Pressure P3 to increase above Pressure P2, thus opening the TV. P2, thus opening the TV.
The Tangguh LNG Gas Fields: Conceptual Development Overview
Authors: Kasim Achmadi T. , Titus Iwan , Roberts J. Wayne , Bulling Tom P.
Published: December 2007

Recent exploration, appraisal and certification activities have established certified proved gas reserves in excess of 14 trillion standard cubic feet (TCF), and potential reserves of 24 TCF, for the fields already identified in Berau Bay, Irian Jaya, Indonesia1. The project to develop this gas resource has been named Tangguh LNG. This project encompasses production and processing of natural gas to manufacture liquefied natural gas (LNG) plus storage, loading and shipping for markets in the Asia-Pacific region. The goal of Tangguh LNG is to create a positive, progressive development with mutual benefit to business and the community in which it is operated – and which does no harm to the environment. This paper describes some of the conceptual upstream development planning that has been carried out in support of the Tangguh LNG project.

The conceptual development planning is based on the data from an extensive drilling and seismic campaign that was conducted to establish the magnitude of the gas reserves found mostly offshore in six fields, including the giant Wiriagar Deep and Vorwata gas fields. The resultant integrated dataset contains substantial log, core, pressure, drill stem test and seismic information and was the basis for the reservoir and fluid descriptions used in models for conceptual planning.

Both analytical and numerical simulation models have been used for conceptual development planning. Single well analytical models have mainly addressed well deliverability. Simulation models have been used to investigate the interaction of several major reservoirs in the six gas fields, an aquifer, and a surface network supplying gas to the LNG plant. Pipeline simulation models have been used to investigate the possible use of multiphase pipelines to supply gas to the plant, thereby simplifying the offshore facility design.

For conceptual development planning, the scope of initial development for the Tangguh LNG project has been designed for a two train LNG plant with an average sales volume of 6 MTPA. Highly prolific wells, a large reserve base, and an uncomplicated offshore development setting result in an efficient, low cost, and highly reliable LNG project for this design basis.
Measurement of Residual Gas Saturation in Water-Driven Gas Reservoirs: Comparison of Various Core Analysis Techniques
Authors: Mulyadi H. , Amin R. , Kennaird T. , Bakker G. , Palmer I. , Van Nispen D.
Published: December 2007

The objective of this study was to derive values of residual gas saturation (Sgr) for water-driven gas reservoirs using various core analysis methods: steady-state waterflood, co-current imbibition, centrifuge and counter-current imbibition. The relative dearth of published data comparing various core analysis methods, and the uncertainty in estimating Sgr for gas reservoirs under water-drive, resulted in the decision to attempt to determine an optimum laboratory protocol to evaluate Sgr.

Core samples from various reservoirs, representing a range of porosity and permeability values, were selected for testing. The various analyses were conducted to represent a range of field displacement mechanisms where viscous, capillary or gravity forces may dominate.
Experimental Investigation into Near-Critical Phenomena of Rich Gas Condensate Systems
Authors: Zheng Xitan , Sheng Pingping , Li Shi , Luo Kai , Dai Zhijian
Published: December 2007

The petroleum exploration pushes the frontier to deeper strata with more near critical fluids. However, the documented studies on near critical behavior of complex fluids are absent, especially for unsymmetrical multi-component and real reservoir fluids. Thus the phase behavior of near critical systems has attracted considerable attention. This paper presents some experimental results of near critical phenomena of three rich gas condensate systems. The measurements are performed with mercury-free PVT equipment. The Lab. fluids consist of one six-component hydrocarbon mixture and two field samples. The results presented contain the critical points, bubble- and dew-point lines, optical phenomena and unusual phase transitions in near critical region, etc.

The percentage-liquid volumes at several temperatures are recorded in detail for all fluids, and are cross-plotted to determine the critical points in pressure-temperature diagram with no further attempts to experimentally determine the precise critical parameters due to the limitations of the PVT equipment. Instead of the opalescence previously reported for carbon dioxide, the reddish-brown color is observed in near critical regimes for three fluids, this may be attributed to the complexity of the fluids. Comparison of the near-critical phenomena obtained in this study shows a large difference between the synthetic and real systems.

Surprisingly, the unusual phase phenomena are observed for the synthetic mixture and one field sample. That is, during the constant composition expansion process the dew-point phase change occurs twice above the critical temperature, and correspondingly dew- and bubble-point phase changes occur sequentially below the critical temperature. In the later case, an interesting finding is that the fluid can not be clearly classified into gas or liquid according to the usual experimental classification of fluid types in PVT cell. In two cases, the first-appeared fluid at the bottom of PVT cell first disappears at the same lower-pressure with pressure depletion, although the temperatures are different. To our best knowledge, the unusual phenomena occurring at high temperature up to 100 Celsius degrees is reported for the first time. These observations present a new challenge on the gas-liquid concepts widely used in engineering fields, and strongly imply limitation of popular two-phase assumption of the PVT calculation in numerical simulation.

The results presented herein are of high value from the theoretical and practical viewpoints, and can find wide applications in various fields involving petroleum industry, e.g., formation fluid sampling, classification of fluid types, well testing, the optimum of the profitable development strategies of gasfield, etc..