bluuebunny/crossref_metadata_2025 huggingface dataset:
Fluid Frictional Diversion Technique for Sequential Multistage Horizontal Stimulation
Authors: Grieser Bill , Wiemers Tim , Hill Britt
Published: December 2007

This paper describes a method for fracture-stimulating noncemented horizontal wells in multiple stages. For existing openhole horizontal wells, an open-ended nonperforated liner is inserted nearly to the toe of the horizontal section. The liner is hung off inside intermediate casing, and the liner top is packed off. The liner is not cemented in place. The first fracture-treatment stage is pumped through the liner and out its end, creating a fracture near the toe of the horizontal section. Perforating guns are then positioned downhole to create holes in the liner at the next fracture initiation site. After perforation, the gun is removed, and the next fracturing stage is pumped at a high rate. This process is repeated for each treatment stage, spacing fractures along the horizontal interval.

Treatment diversion is accomplished with high injection rates and a fluid-friction pressure drop. The horizontal distance between fracturing stages is carefully designed for optimizing all diversion parameters and maximizing the effects of fluid friction in diverting fluid into each new perforation set. No special liner equipment, mechanical diversion equipment, or packers are used.

For an existing openhole horizontal completion, the design is based on the liner size, the diameter and number of perforations, the distance between perforations, and the injection rate required to achieve diversion. This technique is most effective when the hole size, pipe size, and horizontal length are in a specific range.

A circuit analogy of a parallel electrical circuit with multiple resistors graphically demonstrates the calculation of individual injection rates and treatment volumes required to divert the inj ection fluid through the various flowpaths into multiple sets of perforations.

In one field case, a high-volume fracture-stimulation treatment was pumped down intermediate casing into an open horizontal hole at a high rate. The post-fracture production was less than expected. Later, a solid liner was inserted into the open hole, and the operator used the frictional diversion technique (FDT) to distribute fractures at selected sites along the horizontal section. An incremental production increase, a lower decline rate, and increased reserves were obtained.
Improving Reservoir Performance of the Painter Reservoir Unit
Authors: Ring J. N. , Heffner T. A. , Elliott M. W. , Zack J. G.
Published: December 2007

A rigorous evaluation of Painter and East Painter Reservoir fields produced extraordinary results, both economically and technically. The evaluation's goal was to identify remaining hydrocarbon potential, if any, and to reduce operating expense. The results of the evaluation have initiated and sustained a highly successful horizontal drilling program, increased reserves by extending full pressure maintenance (with nitrogen injection) by several years, and substantially improving current financial performance.

Painter and East Painter Reservoir fields, located in Uinta County, WY, are collectively known as the Painter Unit, because both fields produce from the Nugget formation and are tightly integrated through common facilities. In 1995, the Painter field was rapidly approaching its economic limit after producing only 25% of the OOIP, and immediate blowdown (cessation of full pressure maintenance) seemed inevitable, which would result in reserve losses from both fields because of nitrogen (N2)) supply considerations. This paper will focus on the technical methodology used to improve the performance of these reservoirs, and will share some of the financial results.
Evaluation of Centrifugal Drying for Recovery of Synthetic-Based Drilling Fluids
Authors: Bradford D. W. , Growcock F. B. , Malachosky E. , Fleming C. N.
Published: December 2007

Loss of synthetic-based mud (SBM) on drilled cuttings discharged offshore can add considerably to the drilling fluid cost. In addition, offshore environmental regulations are becoming increasingly strict, causing discharge of SBM to be severely curtailed. To reduce the loss and discharge of SBM, a new mud recovery technology – Centrifugal Drying – was tested as an enhancement to conventional solids control technology on four development wells in the Gulf of Mexico.

Centrifugal Dryers, sometimes called rotating shakers, remove fluid from the cuttings by use of a spinning, screened basket arrangement which imparts a Centrifugal force on the order of 100 G on the cuttings. Cuttings discharged from the shakers are transferred to the Dryer's inlet pipe and are fed by gravity to the distribution cone and support disc. The cone removes the cuttings from the pipe and accelerates and spreads them evenly over the inner surface of the conical screen. Cuttings are held to the screen by Centrifugal force and moved to the exit port via vibratory motion or a sweeper, while the drilling fluid is forced through the screen and recovered.

In the field tests, the conventional solids control equipment left a residue of synthetic fluid on the cuttings (SOC) of 10 to 15% by weight, whereas the Centrifugal Dryer was generally found to reduce SOC to less than 5% by weight (Fig. 1). Furthermore, the cuttings discharged from the unit dispersed readily and produced no visible sheen when released into the sea water under the cuttings discharge line. By reducing the volume of synthetic discharged, a savings of about $100,000 in mud cost was realized over the life of the project (4 wells).
A Novel Technique for Single-Selective Sand Control Completions Allows Perforating and Gravel Packing of Two Zones with Zonal Isolation in One Trip: A Case History from Trinidad
Authors: Waters F. , Singh P. , Baker C. , van Wulfften Palthe P. , Parlar M.
Published: December 2007

Single-selective gravel pack completions with zonal isolation can be very expensive particularly in offshore environment where rig costs are high. Conventionally, such completions involve perforating and gravel packing of each zone separately, with multiple trips in and out of the hole. A typical procedure consists of the following 6 round-trips excluding a wire-line trip to set the sump packer and running in hole with the production tubing: (1) Perforating the lower zone, (2) Gravel packing the lower zone, (3) Running and setting the packer plug to isolate the lower zone, (4) Perforating the upper zone, (5) Retrieving the packer plug, (6) Gravel packing the upper zone, with a GP assembly that includes an isolation assembly for lower zone. The first two trips can be combined into one trip by using a single trip perforating and gravel packing system, reducing the number of round trips to 5. In addition, fluid loss control pills are quite often required after perforating.

In this paper, we present a new technique for single selective sand control completions in cased holes that allows perforating and gravel packing of both zones with a zonal isolation device between the zones bypassed through shunt tubes for gravel packing the bottom zone. This procedure reduces the number of round-trips from 6 (compared to conventional) or 5 (compared to single trip option for the lower zone) to 1, saving a minimum of 4 round-trips, in addition to eliminating fluid loss control pills throughout the whole operation. This technique has recently been used in an BP-Amoco well in Trinidad where the lower zone is expected to water out sooner than the upper zone and the production is commingled. This application resulted in 17% savings to BP- Amoco in completion costs, in addition to an increase in production from 800 bopd to 1,200 bopd. Details of the tool modifications and the field application (design, execution and evaluation) are discussed along with an economic comparison to earlier practices.
A Sampling of Variational Methods
Authors: Rachford H.H.
Published: December 2007

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

THIS PAPER IS SUBJECT TO CORRECTION

Introduction

As an introduction to a session on variational methods in reservoir modeling, the purpose of this paper is to emphasize the rich variety inherent in the structuring of such methods. We illustrate this with a few examples, chosen partly to suggest that there may remain more such methods yet to be discovered and tried than methods already known and tested. This paper is not intended to be a survey, nor is it intended to present a full account even of the ideas illustrated. Indeed, a complete compendium of known variational methods potentially applicable to reservoir simulation and all the details of the methods discussed would be needlessly lengthy and distract from our main purpose: inspiring the imagination of the reader to the exciting potential of that which may yet come.

The variety of variational methods can best be illustrated by showing examples of a number of ways to treat the same problem. For this it is helpful to choose a simple system which retains the character of reservoir simulation problems. For this we consider the equations on a bounded region Rn for 0 t T

(1)

(2)

where a and are strictly positive smooth functions, Q(x,t) is flow data, = u if Q 0, and (x,t) is data for Q greater than 0.
Revitalizing An Aging Field - Tinggi Production Decline Mitigation
Authors: Kabir A. H. , Othman M. , Talib M. , Hitam S. , Janor M. , Osman A. , Yunos A.
Published: December 2007

Abnormal production decline causes concerns like high operating cost, premature field abandonment resulting in reserves loss and staff demoralisation, all of which have an adverse effect on an E&P company. Operational problems like high sand & emulsion, high scale deposition in the production system adds to the normal challenges of an aging field, making decline analysis more complicated where actual reservoir production decline gets masked by non-reservoir factors. Overcoming all these operational challenges as well as natural production decline calls for innovative thinking and a holistic approach, especially because all the interrelated problems need to be addressed simultaneously and that too sometimes with insufficient data. Reservoir productivity, tubing and surface facilities performances must be optimised as an integrated system. Otherwise, isolated efforts at various parts of the production system are bound to give poor results.

In this paper we describe a case history of an integrated production optimisation effort undertaken on Tinggi field in offshore Terengganu, Malaysia. The field suffers from operational problems like sand, emulsion and scale resulting in widespread equipment malfunction, measurement problems, erosion of valves, chokes, orifices etc. Production declined sharply at a rate of about 26% per year over 1994 to 1997. In early 1998 it was producing 5.8 MSTB/d of oil with a water cut of about 90%. A multidisciplinary team was then formed in order to mitigate this sharp decline which threatened the viability of the field's operations. The team took an innovative approach in coming up with practical and cost effective solutions by studying all the problems and their correlation. All the key operations personnel were interviewed in order to gather information vital to diagnose all the problems systematically. Despite lack of sufficient good quality data (caused by operational problems) the team came up with solutions, implementation of which were gradual and phased, in order to minimize risk in the face of many uncertainties. Production started picking up immediately and the field's current production is 9.5 MSTB/d (in June 1999) with further production gain yet to be realized through additional perforations campaign targeted in October 1999. Most of the earlier solutions were implemented at minimal additional cost. The company plans to extend the result of this study to other fields in a more proactive manner.
Semi-Direct Iterative Methods in Numerical Reservoir Simulation
Authors: Letkman J.P.
Published: December 2007

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

In the past efforts in reservoir simulation have been directed to efficient techniques for solving the set of simultaneous equations arising in multi-phase multi-dimensional fluid flow. Techniques which have been investigated have included both direct solution and iterative methods such as SOR, ADIP and SIP. Iterative techniques have received greater attention since direct methods usually require significantly more computer storage and computing time. Direct methods have been the only alternative for problems which are insolvable with iterative methods, and the direct solution approach becomes competitive for those problems which are slow to converge. problems which are slow to converge. A semi-direct iterative approach is described which extends the capability of iterative methods to solve the more complex problems which result from severe heterogeneities due to geometries or reservoir properties. The semi-direct methods investigated in this paper determines the advantages of including additional diagonals in the triangular decomposition matrices. If all diagonals are included in the triangular matrices the semi-direct method becomes equivalent to the direct method. The investigation showed the asymptotic convergence rate on a computational work required basis was approximately equal to SIP for the model problem proposed by Stone. It achieved faster convergence for the heterogeneous model problem. For some complex problems the method will obtain convergence where SIP fails to converge or converges slowly.

Introduction

Finite difference approximations to the parabolic and elliptic partial differential equations usually lead to a system of simultaneous equations. These equations may be solved directly by elimination methods or by iterative methods such as relaxation, successive over-relaxation, alternating direction iteration or the strongly implicit procedure. procedure. The direct method is efficient for small problems but computer time requirements become excessive for multidimensional problems involving several thousand mesh points. The direct method requires computational effort of the order of IJ for IJ equations in two dimensions and of the order IJ K computations in three dimensions.
A Comparative Evaluation of Different Versions Of the Strongly Implicit Procedure (SIP)
Authors: Suarez A. , Ali S.M. Farouq
Published: December 2007

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

The well-known Strongly Implicit Procedure (SIP), introduced by Weinstein, Stone, and Kwan, was tested for two- and three-dimensional, two-phase reservoir flow problems. Additionally, it was evaluated for the two-dimensional Laplace's equation, where the exact solution was known.

The evaluation consisted in the comparison of the convergence behavior of the SIP algorithm where a single set of equations is used for all iterations, with the algorithm employing two sets of equations, one for odd-numbered iterations, and the other for even-numbered iterations. Also, the effect of the number and ordering of the iteration parameters on convergence was investigated. The algorithm for odd numbered iterations has already been reported by Weinstein et al. The algorithm for even numbered iterations was derived, and is given in this paper.

It was found that less than 10% additional computational effort was expended when using the odd-even iterations algorithm as compared to the original odd-numbered iterations algorithm. However, the odd-even iterations algorithm permitted a significant improvement in the permitted a significant improvement in the results: the material balance errors decreased, and the residuals were lower. The residuals decreased by several orders of magnitude when the convergence tolerance was tightened.

For both versions of SIP, the number and ordering of the iteration parameters was found to have a profound effect on the convergence behavior. Any significant trend was not apparent, however.

It is recommended that the odd-even iterations version of SIP should be used for reservoir problems, and that trial runs should be carried out to determine the optimum number of parameters and the best (e.g. increasing, parameters and the best (e.g. increasing, decreasing, etc.) ordering of the same. The paper discusses these factors for the reservoir paper discusses these factors for the reservoir problems tested. problems tested

Introduction

The Strongly Implicit Procedure (herein-after referred to as SIP) is a highly successful algorithm for the iterative solution of systems of linear equations arising from the application of implicit differences to reservoir flow problems. The advantages of SIP over Alternating problems. The advantages of SIP over Alternating Direction Implicit (hereinafter referred to as ADI) and Successive Overrelaxation (hereinafter referred to as SOR) procedures have been discussed in the literature.
A Steam-Soak Well Model for an Isothermal Reservoir Simulator
Authors: Williamson A.S. , Drake L.P. , Chappelear J.E.
Published: December 2007

An isothermal reservoir simulator may be used to investigate the field-wide application of the steam-soak process. Thermal effects, which are confined to regions close to the soaked wells, are introduced using a semianalytical procedure for calculating fluid production rates. This takes account of saturation and temperature changes in the vicinity of the soaked wells.

In this paper we describe a semianalytical model of the steam-soak process (a steam-soak well model) that extends the use of a conventional isothermal reservoir simulator to cover steam-soak operations. With the availability of satisfactory thermal reservoir simulators, the need for a steam-soak well mode perhaps requires some explanation. Using perhaps requires some explanation. Using current computational facilities, the number of steam-soaked wells that can be included in a thermal simulation is severely limited. The impact of soaking operations on the general reservoir performance (e.g., reservoir pressure changes, oil migration from nonsoaked areas) is therefore not easily ascertained. This situation is similar to a water-coning situation. The detailed behavior of one or a few wells where significant water coning occurs may be investigated using a simulator capable of elucidating the fine flow details around a well. However, a field-wide simulation require a different approach, e.g., the use of a coning well model.
A Review of Riserless Drilling Alternatives
Authors: McLeod Wilfred R.
Published: December 2007

The development of mobile offshore drilling rigs has steadily progressed since their inception, but the nature of the development has been more evolutionary than revolutionary. The advent of semisubmersible and dynamically-positioned rigs has had a significant effect on the capabilities of the equipment. However, the drilling systems have been adapted with only slight changes from those used onshore. As drilling progresses into the deeper waters of the continental margins, the use of conventional marine drilling systems will present an increasing number of problems.

One of the basic and most challenging problems in deep water operations is the marine riser, which is used to provide a conduit for well returns, to guide the drill pipe into the hole, and to serve as a support for control cables and choke and kill lines. In deep water, the riser requires supplementary buoyancy to achieve a better stress distribution and reduce the requirements for riser tensioners. This supplementary buoyancy substantially increases the unit cost of a riser joint while, at the same time, more riser is needed. Costs on the order of $1,500/foot or more are not expected to be uncommon for the longer risers.

Many alternatives to the use of the conventional marine riser system for deep-water drilling are already being investigated. These alternatives offer possible means of avoiding big, expensive, hard-to-replace risers and their associated large drilling vessels. Some of the riserless drilling alternatives given in the literature, including patents, are reviewed. An attempt is made to ascertain which alternatives seem to be most promising.
Problems Associated With the Operation of Offshore Sea Water Injection Systems
Authors: Flammang Robert F. , Medcalfe T.M. , Culligan Paul T.
Published: December 2007

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

This paper was prepared for the SPE-European Spring Meeting 1976 of the Society of Petroleum Engineers of AIME, held in Amsterdam, The Netherlands, April 8–9, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

OFFSHORE SEA WATER INJECTION SYSTEMS

Offshore sea water injection systems are rapidly increasing in number. It wasn't many years ago that you could number the existing systems on the fingers of your hands.

Offshore sea water injection systems have all the problems common to onshore systems plus a few problems inherent to their offshore location.

Offshore sea water injection systems must be more dependable than onshore systems because of their remote locations and the difficulty of getting men and material on site. This is particularly true during winter operations in such locations as the North Sea. Supplies and spare parts cannot be received shortly after a phone call as is common with onshore operations.

The high expense of offshore operations coupled with the high capital cost of the platform make it imperative that plans be platform make it imperative that plans be well thought out and complete before embarking on an offshore sea water injection project. project.

DESIGN CONSIDERATIONS IN OFFSHORE SEA WATER INJECTION SYSTEMS

There are a number of constraints imposed upon the design engineer when he switches from onshore to offshore sea water injection systems. These are imposed by high platform costs and by high offshore operating costs. The design engineer must: Minimize weight on platform Minimize space utilized on platform Minimize maintenance offshore Minimize supply offshore Minimize manpower offshore

THE DESIGN BASIS

The design basis is set by following the principle that the water quality must be only that which enables injection for the life of the project at a minimum injection pressure and minimum cost. pressure and minimum cost.
Metson Attic Steam Drive
Authors: Rehkopf B.L.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

The Metson Pool of the Midway-Sunset Field in California is a steeply dipping viscous oil reservoir. Steam type thermal recovery operations have been in progress in the pool for ten years. pool for ten years. Cyclic steam stimulation techniques have been utilized to take advantage of both natural and induced productive mechanisms. These cyclic operations have proven effective in all but the updip sections of the formation.

An attic steam injection program was initiated as a pilot project in October, 1970 and has since been expanded to include 18 steam injection patterns across the updip edge of the formation. The short term objective of this program is to economically displace and recover oil at the top of the structure by conventional steam flood mechanisms. The long term objective is to accelerate recoveries from downdip cyclic operations.

The excellent results of this project indicate that the attic steam drive process should be applicable to any massive, steeply-dipping, heavy oil reservoir. The process will be of particular value along updip reservoir edges where cyclic steam injection has become uneconomic.

HISTORY

The Metson Lease is located approximately 27 miles southwest of Bakersfield, California at the southernmost tip of the Mid-way-Sunset Field in Section 24, T11N/R23W, SBB and M, Kern County, California (see Figure 1). The discovery well was completed in 1953 and was followed by the drilling of 31 additional wells through 1968. Extensive drilling was not continued at this time in the life of the lease due to relatively poor economics and low production rates prior to the evolution of thermal stimulation.

The advent of cyclic steam stimulation in 1965 was a boon to production from this property as wells that normally would only property as wells that normally would only produce 10–20 BOPD without steam, would produce 10–20 BOPD without steam, would now produce in the 100 + BOPD range.
Comparisons of Polymers Used in Workover and Completion Fluids
Authors: Lipton Daniel , Burnett David B.
Published: December 2007

This paper describes a study of water-soluble polymers used in workover and completion fluids, including xanthan gum and two new biopolymers. Comparisons were made of polymer solution rheology in brines, shear stability, viscosity at elevated temperatures, and formation-damaging characteristics. A mathematical model was used to show the role fluid rheology has in well-stimulation techniques. The paper includes the results of field treatments with xanthan gum fracturing systems.

Introduction

Numerous studies have shown that proper attention to workover and completion fluid design is repaid many times over by the dividends of increased well productivity. The advent of "clean" low-solids fluids has been brought about by industry's usage of water-soluble polymers to provide viscosity and solids-suspending ability.

Today's oil prices are allowing the use of more expensive yet more effective workover and completion fluids. We have made a comparative study in the field of water-soluble polymers to determine if biopolymer systems could be considered as alternates to currently accepted designs and practices. This study presents an examination of polymer properties and attempts to relate polymer properties and attempts to relate polymer performance to workover and completion performance to workover and completion fluid design.

The following eight water-soluble polymers were chosen for the comparative polymers were chosen for the comparative study due to their common use in the field or possible application:

Guar Carboxymethylcellulose Xanthan gum PS-7 (Experimental) Hydroxypropylguar Hydroxyethylcellulose Polyacrylamide (partially hydrolyzed) ZANFLO (Kelco biopolymer)
Application of Neural Networks for Improved Gravel-Pack Design
Authors: Faga A. T. , Oyeneyin B. M.
Published: December 2007

Use of effective sand-control practices has sustained oil and gas production from wells that would otherwise have shut-in. However, a large number of gravel-packs fail early after installation necessitating expensive well intervention. A basic prerequisite to effective control among others is a good gravel-pack design and execution1. This includes obtaining a representative sample of the formation sand, analysing the grain-size distribution and selecting an optimum gravel-size. Gravel-size selection is carried out in relation to formation grain-size to control formation sand movement and using the optimum screen slot to retain the gravel. However, core samples are generally not taken in all wells in a field. In the absence of specific well information, it has become accepted practice to use offset-well data for designs creating a potential for ineffective gravel-packs. This paper discusses the application of neural networks to obtain real-time, well specific, grain-size distributions and how this input could be used to improve gravel-pack design and achieve optimum sand control. Neural networks have been applied with success to predict grain-size distributions from well logs. The availability of a continuous grain-size profile across an entire reservoir has facilitated comparison between the size of gravel on existing gravel-packs where offset-well information was used and gravel-size obtained based on neural network estimates. The results indicate significant differences. They further demonstrate that the use of estimates of grain-size distribution across the entire reservoir rather than offset well grain-size can lead to improved gravel pack performance and thus significant savings on life-cycle costs.
Field Test of a Novel Drill-In Fluid Clean-Up Technique
Authors: Burton R. C. , Hodge R. M. , Wattie Ian , Tomkinson Jane
Published: December 2007

Horizontal wells continue to be used in applications requiring high production rates. However, many of these wells suffer from low productivity due to ineffective mud cake removal. This problem is most commonly encountered in horizontal wells fitted with sand control screens.

In a recent field test, a new technique was applied to remove the drill-in fluid filter cake in a North Sea horizontal well fitted with a sand control screen. This technique uses an EDTA/ascorbic acid/enzyme mixture to effectively remove calcium carbonate and polymer filter cake. The treating fluid was formulated to provide a controlled, long-term degradation of the filtercake, while minimizing corrosion of the screen, production tubing, and packer. The new technique shows some improvement over previous completion practice which resulted in wells with low productivity associated with flow back of calcium carbonate drill-in fluid solids through prepacked sand control screens.

This paper will review productivity and completion impairment analysis of previous wells, laboratory testing of the new EDTA clean-up system and conclude with field implementation and post-job analysis of the clean-up technique.
Optimizing Production in Fields with Multiple Formation Damage Mechanisms
Authors: Tague James R.
Published: December 2007

Optimizing production in fields prone to formation damage often requires considerable time and effort. In fields with multiple formation damage mechanisms, the challenge becomes even greater. Standard industry practices often fail to remove all of the formation damage or prevent it from occurring for a variety of reasons including improper identification of the damage mechanism and selection of inappropriate remedial or prevention techniques. In this environment, only a well planned, comprehensive approach designed to cover all aspects of formation damage will succeed in optimizing production.
Colloid Chemistry of In-Situ Clay-Induced Formation Damage
Authors: Tchistiakov Alexei Andreevich
Published: December 2007

Clay induced formation damage in the vicinity of injection and disposal wells is a worldwide problem in the petroleum industry. The physical chemistry and dynamics of the internal clay transport are still poorly understood issues. In this paper we give a comprehensive theoretical overview over effect of the main physico-chemical factors on the stability and transport of clay particles in sandstone porous media and their influence on the rock permeability. First we give a short "reservoir oriented" introduction to the DLVO theory (Derjagin – Landau – Verwey – Overbeek) which makes it possible to quantify the interactions between clay particles and the rock matrix in terms of electrostatic repulsive and Van der Waals attractive forces. Secondly, we explain the mechanisms of clay surface charge formation. Than we describe the structure of the electrical double layer around clays. Subsequently we consider in detail the influence of hydrodynamic and physico-chemical factors on coagulation –dispersion of clay particles in sandstone. In particular we describe the effect of interstitial velocity, chemical composition, pH, and temperature of the permeating fluid, as well as clay mineralogy, micromorphology, and composition of the exchangeable cations. Furthermore we describe the effect of structural forces on clay stability, which are often ignored in the petroleum literature. Finally we consider the influence of rock microstructure and clay micromorphology on sandstone water sensitivity.
Improvements in High-Rate Water Packing with Surface-Modification Agent
Authors: Ali Syed , Vitthal Sanjay , Weaver Jim
Published: December 2007

High-permeability wells are often completed with high-rate water packing techniques that bypass production-limiting, nearwellbore damage, which can occur during drilling and completion operations. High-rate water pack completions frequently perform poorly in both hydrocarbon productivity and production endurance. In many cases, this poor performance has been linked to pack permeability damage caused by the fines invading the pack and migrating toward the wellbore.

Designing high-rate water pack completions requires careful planning to ensure that the gravel is sized to physically screen out the naturally occurring mobile fines, preventing them from invading the gravel pack. Normally, the generalized sizing criteria first reported 25 years ago are still the standard for high-rate water-pack completion designs. Under certain conditions, these guidelines result in a pack that effectively prevents fines invasion but is limited in conductivity, which reduces well profitability.

Reports indicate that a new surface-modification agent (SMA) applied to proppant is effectively controlling coal fines in coalbed methane fracture-stimulation treatments. This agent works by making the surface of the proppant tacky, causing the proppant pack to be stable to cyclic production changes and causing fines to stick to the formation-pack interface, thus preventing them from invading the pack. These stimulation treatments yielded long-term fines stabilization and significantly increased fracture conductivity.

Recently reported laboratory studies of this SMA indicated that similar fines stabilization in high-rate water-pack completions could also be expected. Additionally, it was discovered that the gravel size required to prevent fines invasion in the pack could be dramatically increased to allow greatly improved conductivity without jeopardizing pack integrity or fines invasion.

This paper presents results of the first high-rate water-pack field testing with this new surface-modification agent with gravel sized one and two times larger than the gravel normally used. Laboratory studies to support this work are also presented, including development of new gravel sizing criteria and the impact of hydrofluoric acid (HF) stimulation treatments if fines invasion eventually does occur.
Detecting Additional Hydrocarbons and Evaluating Formation Damage By Enhancing Old Electrical Logs
Authors: Allen Rob L.
Published: December 2007

Oil and gas accumulations were frequently underestimated or undetected when old electrical logs were used. Computer enhancements of old logs have revealed additional hydrocarbons. Numerous zones were successfully located and produced. Ratios of enhanced curves frequently distinguish tight zones, formation damage, hydrocarbons in place, and moveable oil. Damaged zones have been detected and treated to help production.
Near Wellbore Cleanup in Openhole Horizontal Sand Control Completions: Laboratory Experiments
Authors: Brady M. E. , Ali S. A. , Price-Smith C. , Sehgal G. , Hill D. , Parlar M.
Published: December 2007

Wellbore cleanup in horizontal, openhole sand control completions has been the subject of many publications in recent years. Although a large majority of horizontal wells have been standalone screen completions, an increasing number of these wells are being gravel-packed, particularly in deep water, sub sea environment where reliability of the sandface completion is of utmost importance due to prohibitively high cost of intervention. In such wells, increased significance of "doing it right the first time" further necessitates an emphasized consideration of wellbore displacement and filter cake removal treatments. Although a substantial amount of laboratory data on filter cake cleanup are available in the literature, a great majority of these data are relevant to non-gravel-pack completions.

In field practice to date, cake cleanup in GP completions has almost exclusively been done after gravel packing and typically involved coiled tubing. Although several new methods have recently been proposed and successfully practiced in several applications (e.g., inclusion of cake-breaking chemicals into gravel-pack carrier fluids, post-GP breaker treatments immediately after GP w/o requiring coiled tubing), laboratory data directly applicable to such conditions have been scarce.

In this paper, we present laboratory data relevant to gravel-packed completions. We show that the cake removal time scales in the presence of a gravel-pack are longer compared to absence of a gravel-pack on top of the filter cake. The degree of delay is shown to depend primarily on carrier fluid viscosity and whether the breakers are included in the carrier fluid or introduced as a post-GP treatment. It is further shown that including breakers in brine during water packing must be exercised with extreme caution since even slow-reacting breakers can yield premature screenout due to increased losses should external cake erosion occur.
System for the Hydraulics Analysis of Underbalanced Drilling Projects in Offshore and Onshore Scenarios
Authors: Silva Valter , Shayegi Sara , Nakagawa Edson Y.
Published: December 2007

As a reservoir is depleted, both pressure and production rates decline and lost circulation or differential sticking problems can hamper or prevent drilling operations undertaken to enhance production, such as in-fill drilling, drilling horizontal sections through the reservoir or re-entry operations. Underbalanced drilling is a workable method to drill in such depleted or low-pressure fields. Another benefit of underbalanced drilling is that it can potentially prevent or reduce near wellbore permeability damage (skin), thus enhancing production, reducing stimulation requirements and delaying water or gas break-through time due to the lower pressure drop required for the same flow rates.

In order to design and realize a successful underbalanced drilling project many important elements must be considered conjointly. This is especially important for UBD operations offshore from floating vessels, where the number of critical issues increases significantly. An integrated analysis method has been developed which incorporates these elements, including multiphase flow calculations, gas and liquid injection rate optimization, hydrostatic gradient and frictional pressure loss calculations, cuttings transport, reservoir fluid influx (gas, oil, or water), and operational procedures such as tripping and liquid unloading.

Software has been developed based on this method so that an engineer can quickly and easily consider and compare the use of different light-weight fluids or to see the effect when varying diverse parameters. The software can model gasified liquid, foam, mist air or non-Newtonian single phase mud for upward or downward vertical and inclined flow as well as horizontal flow. A cuttings transport model resulting from full-scale experimental work is incorporated to delineate the limits of adequate hole cleaning and the effect of operational procedures can be studied.

Different field cases have been modeled with the software and the results have compared well with actual data. A gasified fluid example is included to illustrate the potential of the software.
Borehole seismic: supplying answers to fractured reservoir questions
Authors: Evans R. , Gaucher E. , Randall N. , Vuillermoz C. , Rodriguez S. , Michaud G.
Published: December 2007

The importance of being able to characterise fractured reservoirs in oil field development is widely accepted. This paper discusses two recently developed borehole seismic techniques which have proved to be useful in achieving this. In particular, case histories gathered from recent experience illustrate how these well seismic techniques can help to determine main fracture orientations and densities. One technique involves monitoring microseismic activity taking place in active fractures at the reservoir, the other an analysis of the birefringence effects that apply to shear wave energy when passing through the fracture medium.

Microseismicity occurs in association with geological stress changes. In the case of hydrocarbon reservoirs it can arise naturally from straightforward production, as the result of injection, or hydraulic fracturing operations. In two major surveys in the North Sea the SST500 VSP tool has been used by CGG to successfully record microseismic activity.

In late 1997, CGG participated in a major Reservoir Characterisation Project (RCP VII) designed to monitor the effects of prolonged CO2 injection over the Vacuum field, New Mexico. Seismic data was acquired using conventional surface seismic techniques together with downhole-recorded data, simultaneously recorded using an SST500 tool deployed in a well within the RCP area. One Pwave plus two orthogonal Swave sources shooting into a downhole array comprising of 12 3C receivers gives rise to a 9C/3D dataset. This dataset was processed to provide information on the character of reservoir fracturing through the analysis of shear wave
Stochastic Imaging of Vuggy Formations
Authors: Casar-González Ricardo , Suro-Pérez Vinicio
Published: December 2007

This paper is dealing with modeling a heterogeneous reservoir rock from a Mexican offshore field. The problem is porosity characterization through the use of computed tomography images. The addressed issues include: association of secondary porosity with vugs and fractures, vug connectivity and spatial distribution, porosity associated to the rock, and vugs stochastic imaging. Porosity was obtained from computed tomography images, and calibrated with core data. From these images, exhaustive porosity variograms were obtained, showing a correlation range of about 20 millimeters. Further, use of indicator variables allowed vugs visualization, confirming the assumption that dissolution was the dominant process in vugs genesis. It is showed also that permeability has been enhanced through the connection of vugs by high porosity footprints. This detailed information has been used to reproduce geometry and spatial distribution of vugs through a sequential indicator algorithm. The stochastic images reproduce well vugs spatial distribution, explaining the secondary porosity role in the production mechanism in these reservoirs.
Enhanced Completion Techniques in Naturally Fractured Carbonates in Southern Mexico
Authors: Bailey Jeffrey R. , Perez Jesus , Ritter Wes
Published: December 2007

Integrating the practices of locating, selecting, and acidizing fractures into one focused approach has provided successful results in wells in southern Mexico. Previously these methods handled independently have yielded unpredictable results.

The standard methods of locating fractures within a naturally fractured carbonate do not inherently help in determining which are the important fractures in the geological system. Neither do they indicate which fractures are actually open at a useful distance beyond the borehole wall and will be the main production contributors. Often the drilling processes make both minor and major fractures appear to have equal importance.

In southern Mexico, this network of fractures requires a combination approach to evaluate the candidates. This paper explains how combinations of deeper investigating NMR response, conventional logs, and image logs can be combined to narrow the selection of key fractures. Focusing the subsequent completions on specific fractures allow more investment in actual productive intervals making the stimulation more effective.

Concentrating on the properties of the fractures rather than the host rock enhances the stimulation with the new acid systems available. Focusing on the fractures that will take most of the acid during a stimulation job allows decisions to be made about perforation planning with respect to the other reservoir properties. Perforating decisions and or acid stimulation planning can be used to enhance the fractures not normally sufficiently stimulated. This also allows the decision criteria for perforating to be based around enhancement and final production. Case histories, exclusively from Mexico, demonstrating this technique will be presented, as well as examples of other practices and the results.
Development of the Submerged Arc-Welding Process To Reach High Energy at Low Temperature in the Longitudinal Weld Seam of Line Pipe Used for Gas Distribution
Authors: Barbosa Carlos Henrique , Cavalheiro Benedito Carlos , Ferreira Sérgio Ricardo P.
Published: December 2007

Toughness on the welded joint, in special on the heat affected zone, is one of the most difficult requirements to be complied, when it is necessary to weld thick carbon steel pipes, with wall thickness over than 16 mm. Basically, it is defined by the final microstructure. In the weld metal it is the result of the combination between the hardenability and the cooling thermal cycle, related with welding heat input. In the area around the weld bead, called heat affected zone, it is the result of the welding heat input action on the base metal. It is possible to get a better microstructure in the heat affected zone, more suitable to toughness requirement, if heat input is decreased. Considering the weld metal, there is an appropriate range of heat input, which results in better toughness behavior. In order to get appropriate heat input for thick pipe welding, it was developed the submerged arc process with 4-wire tandem technique for pipe welding and the development benefits are shown on this paper.