bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Recent Gulf of Mexico Cavity Completion
Authors: Palmer Ian , Vorpahl Douglas G. , Glenn John M. , Vaziri Hans , McLennan John 
Published: December 2007

Abstract
Production was dramatically improved by cavitating (intentionally producing sand) an offshore gas well on the Gulf of Mexico Shelf. The cavity completion was conducted over a period of 10 days and involved producing the well through temporary equipment in order to safely produce, collect, and dispose of the produced sand. No hydrocarbon emissions resulted since production could be routed back through the permanent facilities. Following the operations, the well was returned to flow through the permanent facilities at a much higher producing rate, with much lower sand production.
Prior to the cavity completion operations, the well had been choked back to a low gas rate, &lt;1 MMscfd, due to sand production. The low gas rate was insufficient to continuously lift liquids, causing the well to become liquid loaded and/ or slug. The well was evaluated for a sand control completion, but this type of repair was felt to entail too much economic risk due to significant reservoir unknowns. Further evaluation suggested that the well had the attributes for a successful cavity completion.
This paper will discuss the cavity completion evaluation process employed and operational results and learnings. A similar process may be applicable to other wells.
Reserves Addition Due to Minimized Formation Damage With Underbalanced Drilling
Authors: Guo Boyun , Ghalambor Ali 
Published: December 2007

Abstract
This paper provides theoretical analyses of hydrocarbon reserve that can be added by Underbalanced drilling (UBD). For simplicity, the analyses are based on the characteristics of solution-gas-drive reservoirs and deepwater reservoirs. The concept is also applicable to other types of reservoirs.
This paper addresses UBD-added hydrocarbon reserve in two aspects: a) minimizing formation damage so that lower reservoir pressure can be achieved at the same level of abandonment production rate at the end of field development; and b) producing hydrocarbons from those zones in deepwater that are not accessible with overbalanced drilling (OBD) or nearbalanced drilling (NBD).
Our analyses indicate that UBD can add reserve very significantly. An example calculation shows that UBD can increase oil reserves by 7% for a skin factor reduction from 10 to 0 in a low pressure, thin oil reservoir. The same example also indicates that the field development time can be shortened by 38% if the field is developed with UBD. Replacing the high-skin OBD or NBD wells with UBD wells in a depleted field can increase reserves and prolong the economic life of the field. Our analyses of formation pore and fracturing pressure gradient curves from a deepwater field confirm the results of previous studies in that UBD can add deepwater hydrocarbon reserve very significantly.
Rock Mechanics Aspects of Well Productivity in Marginal Sandstone Reservoirs: Problems, Analysis Methods, and Remedial Actions
Authors: Tronvoll Johan , Larsen Idar , Li Liming , Skjetne Tore , Gustavsen Øyvind 
Published: December 2007

Abstract
The paper discusses different mechanisms that may explain field observations of productivity decline. In particular, this work reviews some central issues related to rock mechanical processes that may directly or indirectly result in productivity decline and also possible remediation in sandstone reservoirs. Some emphasis is put on particle plugging of the formation itself, screens and gravel packs, scaling in the near-wellbore region, behind the screen/gravel sand production (including quantification of produced sand volume/damaged zone), filtercake mobilization, near-wellbore rock compaction and effects of water breakthrough on rock properties. All these mechanisms are directly or indirectly linked to rock mechanics aspects through local pore pressure changes and induced deformations of the formation rock. Plugging may further induce rock mechanical failure around the well. Two principles of direct sand control are discussed, i.e. borehole re-enforcement (expandable screens, gravel-packing, propped fracturing, chemical consolidation) and filtering (standalone screens, gravel-packs, frac-packs, pre-packed screens) and their impact on productivity upon reservoir depletion, scaling, sand production, filtercake mobilization and fines migration. Different analyses are used to highlight central mechanisms of productivity alteration and to define design parameters. In particular, chemo-mechanical effects upon water breakthrough are discussed with respect to permeability alteration around the wellbore and scale formation. Further, examples will be given that remedial actions to remove scale and other plugging agents in certain cases may harm the formation mechanical integrity, and result in sand production, rock compaction and productivity decline. An example of a simple laboratory test to quantify such loss of rock integrity will be given. The work demonstrates how rock mechanical analysis may guide the selection of completion method, and how proper diagnosis of well performance and formation integrity may guide the selection and design of remedial actions.
Life-of-Well Approach for Optimizing Production – GOM Case Histories
Authors: Proano Eduardo , Patel Yogesh , Thawer Roxy , Al-Harthy Salah , Gadiyar Bala , John Colin , Morales Hugo 
Published: December 2007

Abstract
A life-of-well comprehensive methodology for production optimization is demonstrated through two Gulf of Mexico stimulation treatments in formations requiring sand control. The approach considers the full well history in the process of well evaluation and candidate selection. The treatments were designed for remediation of damage caused by a time-dependent disruption of formation sand and/or sand-control mechanism, including fines migration, proppant instability, and scaling.
Traditionally, data from permanent bottomhole gauges have been used as a valuable tool for well and reservoir management. As demonstrated in this paper, the data can be crucial to the assessment of the evolution of time-dependent skin. The practical result of well or reservoir surveillance and diagnosis from permanent gauge or traditional production data is shown to produce better decisions on stimulation and production management, while maintaining life-long well integrity.
Optimization of an Oil Soluble Scale Inhibitor for Minimising Formation Damage: Laboratory and Field Studies
Authors: Wylde J. J. , McAra E. K. 
Published: December 2007

Abstract
Oilfield scale formation is dependent upon the production of water; as a result most scale inhibitors are water soluble and deployed using an aqueous phase. For treatment of wells that produce only small amounts of water and/or have water sensitive matrices, the use of an aqueous inhibitor can cause many problems. Even with the development of oil miscible scale inhibitors the same problem can be encountered when the incorrect screening procedure has been used in the laboratory.
This study illustrates the importance of using the correct coreflood protocol when evaluating an oil soluble scale squeeze inhibitor. Examples of different procedures for different types of scale inhibitor show that use of the incorrect procedure can seriously influence the formation damage and lead to misapplication in the field. Three field examples are included, comparing laboratory evaluation and field specific studies of different types of scale inhibitor, explaining why different formation damage mechanisms are seen in the field and sometimes not recreated in coreflood experiments.
The study goes on to describe the development of a range of truly oil soluble scale inhibitors, which preclude any aqueous phases, and have been specifically developed to minimise formation damage caused by aqueous and oil miscible scale inhibitors. The products have been screened for use in several fields which have historically had formation damage issues with both aqueous and oil miscible scale inhibitor squeeze products. Finally, the paper will talk about the consequences this has for field application based upon a field trial using the new, truly oil soluble scale inhibitor.
The Challenge that Completion Types Present to Scale inhibitor squeeze Chemical Placement: A Novel Solution using a Self-Diverting Scale Inhibitor Squeeze Process
Authors: Feasey N. D. , Jordan M. M. , Mackay E. J. , Collins I. R. 
Published: December 2007

Abstract
The control of inorganic scale deposition within the reservoir under both natural depletion and injection water support has been a challenge to the oil industry for a number of decades. The challenge has remained identifying the location of water breakthrough within the production interval and the subsequent injection of scale inhibitor into these zones to prevent scale formation within the near welbore and production tubing. As completion technology has advanced, and more complicated completions have been developed and installed to increase the rate of oil recovery, the challenges of water management and scale control have become significant factors if long term production from these wells is to be maintained.
This paper will outline the challenges of chemical deployment via bullheading into subsea wells completed in high permeability reservoirs with sand control technology. The factors considered when designing a self-diverting scale inhibitor system will be outlined in terms of viscosity profile of the chemical and overflush fluid, impact of temperature on fluid viscosity, pump rate, shear effects, tubing diameter vs. wellbore friction and the impact of radial flow on viscosity. Modelling data from vertical and horizontal production wells will be used to illustrate the challenges that pump rate changes and a self-diverting scale inhibitor system has to overcome to allow effective deployed of scale inhibitor without the need for coiled tubing in long (500ft to 3,000 ft) wells in 2 Darcy reservoirs.
The value of this technology in terms of the economic factors will be outlined with field examples where coiled tubing and bullhead applications will be compared and contrasted to illustrate the value in terms of total cost of operation that the self-diverting technology can offer.
Pushing the Limits in Hydraulic Fracture Design
Authors: Demarchos A. S. , Chomatas A. S. , Economides M. J. , Mach J. M. , Wolcott D. S. 
Published: December 2007

Abstract
In a number of previous publications we have introduced the concept of Unified Fracture Design (UFD) with a central theme of maximizing the dimensionless productivity index (JD) following a hydraulic fracture treatment. We have shown that for a given mass of proppant to be injected in a well with an assigned drainage in a reservoir of a given permeability there exists a specific dimensionless fracture conductivity at which the JD becomes maximum. We called this the optimum conductivity. Smaller and larger values of this conductivity result in smaller JDs. All the important fracture and reservoir magnitudes of permeabilities and volumes are related through the Proppant Number. Once the optimum conductivity is determined (which for a large range of Proppant Numbers is equal to 1.6) then the ideal fracture dimensions (length and width) are de facto set and they should be considered as the desirable target.
For each injected proppant mass there is a corresponding Proppant Number and at the optimum conductivity the dimensionless PI can be readily determined. Increasing the proppant mass or the proppant-pack permeability would result in an increase in the JD, which has a maximum limit of approximately 1.9. This value can never be accomplished in reality and there are three reasons preventing it, one economic and two physical. The economic reason is obvious. Increasing the job size would result in the flattening of benefits, not justifying the incremental costs. In the same vein, using a much better (and more expensive) proppant may not be justified by similarly flattening benefits.
Of the physical problems, the first affects low-permeability reservoirs where the indicated fracture width may be too small; it cannot be less than three proppant diameters. For high-permeability reservoirs, indicated very large widths will certainly result in very large net pressures, exceeding operational limits. The latter may also lead to unacceptable fracture heights.
We present here a series of parametric studies pushing the physical limits of fracturing in a wide range of reservoirs by injecting very large proppant volumes and experimenting with extraordinarily large proppant sizes (large proppant pack permeabilities) seeking the maximization of the JD within reasonable economic limits. This work appears to be particularly suited for high permeability formations and it shows that current industry practices are overly conservative and timid and a more bullish approach would lead to major production enhancement benefits.
An Innovative System for Complete Cleanup of a Drill-In Fluid Filter Cake
Authors: Todd Brad , Ali Syed , Whitfill Donald L. , Haggerty Tim 
Published: December 2007

Proposal
As part of a comprehensive program to develop delayed filter cake breakers, a drill-in fluid with magnesium oxide (mag-ox) bridging particles and an ammonium chloride-based cleanup solution was developed. The mag-ox particles are insoluble in water and standard drill-in fluid-based brine such as sodium chloride, but these particles are readily soluble in ammonium chloride or ammonium citrate. Thus, an ammonium chloride-based cleanup can be formulated that will dissolve the bridging particles and other drill-in fluid components without using acid-based systems. Because this technology was of specific interest for injector well applications, a laboratory study was undertaken to evaluate this novel system. This paper summarizes laboratory work and radial flow loop test results, and discusses possible field applications.
Filter-cake cleanup of injection wells can be especially problematic because operational constraints often preclude backflowing the well to remove the residual filter cake. Consequently, injection remains impaired if the residual filter cake is not removed by other means. The highly reactive nature of standard treatments may remove the filter cake at the point of circulation before the treatment can be placed over the entire openhole interval. A need exists for cleanup solutions that have a delayed effect on filter-cake integrity, allowing the cleanup solution to be circulated across the entire interval. Preferably, the treatment&#39;s reaction with the filter cake would commence when the entire solution is in place and continue until the filter cake is uniformly removed. The ideal placement of a treatment would be in the gravel-pack carrier fluid, where it would provide enough of a delayed reaction to allow the gravel pack to be placed with an alpha/beta wave technique before fluid-loss control is lost.
Predicting and Monitoring Fluid Invasion in Exploratory Drilling
Authors: Martins A. L. , Waldmann A. T. A. , Aragão A. F. L. , Lomba R. F. T. 
Published: December 2007

Abstract
The present study proposes, through the coupling of a linear filtration formulation (lab configuration) and a radial single phase formulation (wellbore vicinity), to predict fluid invasion depth of drilling fluid filtrate in the reservoir rock. Modeling is validated with linear and radial lab tests as well as with resistivity logs run in offshore wells from Campos basin.
The proposed methodology is a requirement for optimum drilling fluid design to be used in the drilling of reservoir sections in both exploratory and development wells in Campos Basin, offshore Brazil.
An Investigation of the Extensional Viscosity of Polymer Based Fluids as a Possible Mechanism of Internal Cake Formation
Authors: Khan R. , Kuru E. , Tremblay B. , Saasen A. 
Published: December 2007

Abstract
Formation of internal cake due to the invasion of reservoir rock by drilling, completion, and fracturing fluids is known to be one of the major causes of productivity reduction. Although the causes of internal cake formation are relatively well identified, the actual physical mechanisms involved in internal cake formation are yet to be understood. In particular, a quantitative means of relating physical properties of fluids to the degree of productivity reduction are not well established. A detailed investigation on the role of the rheology of viscoelastic fluids on the formation of "internal filter cakes" is, therefore, needed.
The extensional viscosity for pure liquids without any structure is 3 times the shear viscosity. For these liquids, contribution of the extensional viscosity to the pressure loss is, therefore, constant and often neglected. However, for viscoelastic fluids, such as polymer based drilling and completion fluids, the extensional viscosity may be several orders of magnitude larger than the shear viscosity. This will lead to a significant increase in pressure loss, which is very often attributed to the development of internal cake.
A series of core flow experiments have been conducted to investigate the possible relationship among the polymer concentration, fluid extensional viscosity, shear viscosity, filtration loss characteristics, and pressure drop across the core samples and hence, any change in the original rock permeability.
Results of extensional and shear viscosity measurements, API filtration loss tests, and formation damage tests conducted by using two different Partially Hydrolized Polyacrylamide (PHPA) solutions (1.5 and 3.0 lb/bbl) are shown in this paper.
Comparison of the PHPA test results with the previously published Xanthan Gum (XG) test results are also provided.
Strategy for Designing an Optimum Drill-In Fluid Utilizing Rock and Petrophysical Properties
Authors: Luyster M. R. , Ali S. A. , Guzman J. , Mason S. , Dick M. 
Published: December 2007

Abstract
Relatively heavy crude production has historically been a problem in vertical completions in mature and new development fields in the Gulf of Mexico. Horizontal wells have been utilized to minimize water coning in potential completions that are close to the oil/water contact. However, horizontal completion costs are typically 60% more than vertical completions, consequently well and fluid design are critical to minimizing costs associated with drilling (fluid losses, wellbore stability, etc.).In addition to the engineering challenges for horizontal drilling, formulating a reservoir drill-in fluid (RDF) that minimizes invasion and fluid losses to the reservoir, provides compatibility between the reservoir fluids and the RDF fluid, and readily cleans-up is critical to success.
This paper will demonstrate the use of sidewall and conventional core material and subsequent petrophysical techniques to design a compatible RDF system. Core material from offset wells and previous vertical wells in several sands were utilized to develop bridging-material blends, determine sorting, texture, and particle and pore size.The authors discuss the advantages and disadvantages of using this type of material as well as that of a relatively new computer technique that allows a pore-size distribution to be rapidly calculated from core material.Another technique utilizes the rock attributes and log information in conjunction with a rock catalog to facilitate rapid determination from analogs. This type of data, in turn, can ultimately be utilized to design an RDF system.As such, this method will also be described and contrasted with traditional methods.
Finally, case histories from several recently drilled horizontal wells that incorporated the subsequent RDF bridging-solids design using the aforementioned techniques will be presented. Fluid losses and solids loading will be examined with respect to the RDF designs.
A Potassium Formate Milling Fluid Breaks the 400° Fahrenheit Barrier in a Deep Tuscaloosa Coiled Tubing Clean-out
Authors: Messler D. , Kippie D. , Broach M. , Benson D. 
Published: December 2007

Abstract
This paper will detail the successful operation to remove a barite plug from this wellbore using a viscoelastic fluid, with true yield stress properties. Extensive field rheologies, pumping rates, and pressures were captured; and compared with those predicted by modeling. The mechanical and chemical maintenance of the fluid system during the operation will also be discussed.
The development of this fluid enabled a coiled tubing intervention to go forward, as planned. In contrast to an earlier attempt, the coiled tubing successfully reached total depth (TD) while properties stayed within safe operating parameters. The milling operation was carried out, with over 185 ft of hole being recovered from the initial coiled tubing tag at 19,412 ft. At no time was there any danger of ‘sticking the coiled tubing’ or being unable to circulate due to excessive friction pressures.
The successful field application of this technologically advanced fluid system in combination with sophisticated computer engineering software, gives the industry a new tool in attempting deep HTHP coiled tubing workovers.
Brine Effects on Hydration Rates for Polymers Used in Completion and Workover Operations
Authors: Beall Brian B. , Monroe Terry D. , Vollmer Daniel P. , Hanna Farid T. 
Published: December 2007

Abstract
Polymers used in completion and workover operations can consist of cellulose, cellulose derivatives, guar and guar derivatives. Normally these polymers are used in completion and workover fluids consisting of potassium, sodium and ammonium chloride. As more wells are being completed in deeper and hotter environments, fluids composed of calcium chloride, calcium bromide, zinc bromide and combinations of all three are being used to control well pressures.
Studies were conducted on hydration rates in various brines for these polymers and are presented in graphical form. A correlation was also established to predict the hydration rates and the ultimate viscosity for hydroxyethylcellulose at temperature based on brine viscosity. These correlations are particularly useful for field operations during cold weather months.