bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diversion and Cleanup Studies of Viscoelastic Surfactant-Based Self-Diverting Acid
Authors: Lungwitz Bernhard , Fredd Chris , Brady Mark , Miller Matthew , Ali Syed , Hughes Kelly 
Published: December 2007

AbstractA self-diverting-acid based on viscoelastic surfactant (SDVA) has been used recently on stimulation treatments of carbonate formations. The new system has been proven successfull in more than 250 field applications.The decrease of acid concentration during the spending process viscosifies the fluid by the transformation from spherical micelles to an entangled wormlike micellar structure while penetrating the carbonate rock. The highly viscous fluid acts as a temporary barrier and diverts the fluid into the remaining lower-permeability treating zones. After treatment, the SDVA barrier breaks when contacted either by formation hydrocarbons or pre-and post-flush fluids. Quantifying diversion, fluid efficiency, and cleanup are important factors for successful candidate selection and job design. Laboratory tests defining these key factors are presented in this paper.This paper demonstrates the diverting ability of the acid as a function of permeability, characterized by introducing the concept of maximum pressure ratio (dPmax/dPo) supported by core-flow and acid conductivity tests using limestone and dolomite cores. Results demonstrate high dPmax/dPo in high-permeability cores and low dPmax/dPo in low-permeability cores. Retained permeability measurements are presented that assesses the level of cleanup. Flow initiation experiments of spent acid systems with gas and brine were performed to illustrate the cleanup behavior of SDVA in comparison to gelled acid systems under conditions encountered in gas and oil wells. The results indicate that SDVA systems clean up easily and that SDVA provides higher regained permeability than conventional gelled acid systems.
Optimizing Drill-In Fluid & Completion Cleanup Processes for Openhole Horizontal Gravelpacked Completions in Low Temperature Environments
Authors: Davis E. , Hodge R. , Dick M. , Mason S. , Martens H. 
Published: December 2007

Abstract
Drilling and completing extended length horizontal wellbores through low-temperature (&lt;80°F) unconsolidated, high permeability reservoirs presents significant technical challenges and operating complications that can significantly impact initial well performance. Integrating the design and functional attributes of reservoir drill-in fluids with the various completion fluids, and their application processes, can produce significant benefits with respect to well performance.
This paper presents and discusses the technical challenges and issues confronting the design and implementation team responsible for installing the first horizontal openhole gravelpacked completion on the North Slope of Alaska. The gravelpacked horizontal well, 2T-218 was installed in the Greater Kuparuk Area's Tabasco field. The paper presents a case history detailing the fluids integration process and validation efforts utilized to develop and implement the reservoir drill-in fluid and filtercake cleanup treatments applied to the gravelpacked completion. The paper discusses the specific design criteria for the various fluids used in the drilling and completion operation, the design and laboratory testing process to determine the optimum recipes, the results of these lab tests, a summary of each field operation, and provides a synopsis of well performance obtained.
The unique conditions of application for this well in the Tabasco field in Alaska include: Medium to coarse pebbly unconsolidated sand and siltstonesHigh permeability contrast (1000 to 10,000 md)Low Bottomhole Static Temperature (76°F)Low Bottomhole Pressure 6.7-lbm/gal equivalent.
The principle issues with which the team had to deal were: Management of the properties of reservoir drill-in fluids utilized at low circulating and bottomhole static temperatures.Effective hole cleaning properties required for the horizontal section.Drilling fluid losses to the 6.7-lbm/gal reservoir.Wellbore stability and stuck pipe through the unconsolidated sand.The potential for formation damage of the high permeability & low-pressure reservoir interval.Adequate lubricity in order to successfully drill the horizontal section.The ability to degrade the drill-in fluid filtercake from behind a sand exclusion liner and coarse (12/20) gravelpack.The risk of and the methods to mitigate potential corrosive damage to the 13-CR completion equipment in the event of prolonged exposure to the filtercake cleanup treatment fluid.The reaction rate, uniformity, and efficiency of filtercake cleanup treatments.The effect of lubricants with respect to filtercake cleanup treatments and retained permeabilityThe performance of enzymes utilized in low temperature cleanup treatments.
Application and Performance of Single-Trip, Multi-zone, High-Rate Water Packs in a Mature Low-Pressure, Low-Temperature Gas Field
Authors: Ledlow Lewis B. , Seitz Brian T. 
Published: December 2007

Abstract
A total of six high rate water packs were installed in two wells utilizing a single trip, multi-zone gravel pack technique. The multi-zone gravel pack tool system allowed the installation of multiple gravel packs with a single run into the wellbore.1, 2, 3 This gravel pack system was chosen to reduce rig time and to minimize fluid loss into the low pressure, high permeability gas sands. In this high permeability reservoir, frac packing did not appear necessary for stimulation. The multi-layered reservoir and low strength rock made it highly unlikely that single, planar fractures could be created that would grow and connect up all the individual sands. Emphasis was placed on completion efficiency to minimize the effects of non-Darcy flow that severely limit the productivity of conventionally completed wells.
This paper describes the nodal analysis and well test evaluation techniques used to assess the rate limiting effects and completion inefficiencies of existing completions in this field. Also presented are single-trip, multi-zone gravel pack completion design and installation techniques that provided two to five times the productivity over conventional completions in a mature, low pressure, low temperature gas field. Sustained deliverability from the two completed wells has deferred both rig and non-rig wellwork for several years.
Designing and Obtaining Optimally Productive High-Rate Gas Wells From Horizontal Openhole Gravelpacked Completions: The Hibiscus Experience
Authors: Folefac A. , Hylkema H. , Mason S. , Graham A. , Svoboda C. , Guzman J. , McCartney R. , Patey I. 
Published: December 2007

Abstract
This paper summarizes the systematic methodology & engineering process employed to identify and refine the highly effective fluid-train solutions used to drill, and install the highly productive, long horizontal gas well completions of the NCMA Hibiscus Project offshore Trinidad. It presents and discusses the unique fluids design, pre-project evaluation, and the integrated application efforts undertaken to: 1.) Minimize formation and completion damage; and 2.) Maximize gravel-pack placement and filtercake removal efficiencies. The paper will identify important reservoir drilling and completion fluid service integration points (metrics), laboratory validation methods employed, and provide completion process details that led to the successful high-rate gas well installations in an unconsolidated sandstone reservoir.
Specific topics discussed will include: the design and implementation of: the optimized Reservoir Drilling Fluid (RDF), RDF to Completion Fluid displacement, gravelpacking process, and the filtercake removal treatment. Finally, the paper will present case histories of the five completions installed in the Hibiscus reservoir and provide comparisons of: 1.) RDF drilling performance, 2.) gravelpacking efficiency, and 3.) well performance (productivity) of a stand-alone screen completion versus the gravel packed wellscreen completions that employed the unique RDF and filtercake cleanup treatments.
Laboratory and Economic Evaluation of the Impact of Chemical Incompatibilities in Comingled Fluids on the Efficiency of a Produced Water Reinjection System: A North Sea Example
Authors: Collins Ian R. , Graham Gordon M. , Stalker Robert 
Published: December 2007

Abstract
As regulatory limits for oil discharge become more stringent and environmental awareness increases, produced water re-injection has become increasingly attractive for operators. However, as offshore developments become more complex, with new fields producing through existing facilities, the PWRI design team must face the problems involved in combining and re-injecting potentially incompatible fluids and/or production chemicals.
The Cleeton facilities in the North Sea provide an example of such a PWRI system. These facilities are the hub for the Easington Catchment Area (ECA) and are due to process fluids from an increasing number of new developments in coming years. This paper describes how the results of an extensive laboratory-based formation damage test program (SPE 80257) were combined with near-wellbore injection simulations and economic modelling studies to enable the economics of the treatment program to be defined. This laboratory study demonstrated that one of the production chemicals present in the expected co-mingled fluids exhibited a significant incompatibility with the formation rock, leading to in situ precipitation near the injection face. This resulted in significant reductions in injectivity. Additional work demonstrated that a number of remedial treatments were available to restore injectivity. Near well-bore injection simulation studies were used to predict the rate of reduction of well injectivity and therefore the timing of requirements for remedial treatments at the injection well. This enabled the economics of the treatment programme to be defined. This in turn allowed the cost benefit of the "PWRI incompatible chemicals" during the production stage to be weighed against the cost of remediation treatments during the re-injection stage. The outcome of this work was to recommend that an alternative chemical strategy was adopted in order to reduce the total costs associated with the proposed PWRI system. Preliminary data from the field implementation of the PWRI scheme is also discussed.
Design, Implementation, Results, and Key Learnings: Case Study of a Novel Single Trip, Perforated, Multi-Zone, Isolated, Frac Pack Completion - Keong Subsea Development, South China Sea Floater Operations
Authors: Davis E. R. , Curran J. , Palthe P. , Saldungaray P. 
Published: December 2007

Abstract
The Keong subsea development is located in Indonesia's Natuna Sea section of the South China Sea in the Block B concession operated by ConocoPhillips on behalf of itself and its co-venturers ChevronTexaco and Inpex. This gas field is one in a series of ConocoPhillips' subsea developments currently underway to fulfill key Southeast Asian long-term gas supply contracts. Therefore, high performance completions are required to drive efficiency in capital-intensive floater operations and subsea environments.
Keong 1 was planned as a cased hole perforated, fracpacked, multi-zone producer. The well was designed to develop a series of laminated high gross to net unconsolidated sands in the temporarily abandoned discovery well, saving both time and money over a new drill. Four separate sand bodies were targeted in the completion. The type of completion was selected to match the existing wellbore configuration, reservoir properties and productivity needs. A sand exclusion completion was designed that would enable the development of the highly laminated reserves.
A single trip, fracpacking, sand exclusion liner completion system to minimize expensive floater rig time and to minimize reservoir/near wellbore damage from well killing operations was also required. A novel combination of multi-zone Alternate Path Technology (APT) isolation packers, with APT sand exclusion liners enabled the simultaneous fracpacking of the three individual zones in a single fracpacking operation. Details of the fracpack design, tool modifications, field application and field observations are discussed.
Acquired pressure data from downhole sensors demonstrates that effective fracpacking of all zones was achieved. Results from subsequent production and pressure build-up data prove the attainment of a zero to negative skin verifying the applicability of the tools and process. This application resulted in savings to ConocoPhillips in completion costs, in addition to the production acceleration benefits of an efficient completion.
The objective of this paper is to present a "conception to production" high performance sand exclusion completion case history from ConocoPhillips' Keong subsea development in the South China Sea. Throughout the paper the design, implementation, operational problems, well performance results and key learnings will be discussed in detail in order to advance the technology and document the proposed completion methodology as an alternative for high deliverability wells.
Efficient Alternative to Control Sand Production in Wells with Oil/Water Contact at the Wellbore
Authors: Brito-Rhor Luis , Kuyucu Osman , Flores Jose G. 
Published: December 2007

Abstract
Sand production has proved to be a severe and often costly problem in many wells in the Oriente basin of Ecuador. Sand production has a negative impact over the productivity and lifting cost when it accumulates as sand plugs in the tubing, the surface flowlines or the surface pipes or vessels, and also when eroding the stages of the electric submersible pumps, shortening their run lives. Traditional techniques used to control sand production, such as conventional screens or gravel packs have been tried by Alberta Energy Company (AEC) in Ecuador resulting in impaired productivities of up to 75%, and therefore, are considered inefficient. Other techniques are not effective because of the broad grain size distribution, and also because the production of AEC in Ecuador typically comes from moderately thin and clean reservoirs, with bottom aquifers in the well. AEC and the majority of operators in Ecuador have not yet been able to control sand production without substantially reducing the oil production.
This paper presents an efficient and economic alternative to control sand production. It consists of a filter that is run in front of the perforations and that once properly packed, can virtually stop the sand without affecting the production of fluids. The completion is simple and significantly less expensive than comparable techniques. The proposed methodology has been tested so far in six AEC producers in Ecuador at flow rates up to 3000 bfpd, controlling the sand without affecting the total flow rate or the flowing pressure. A significant part of the success is attributable to a new procedure, introduced here, to naturally pack the screen.
This work summarizes the experience of AEC Ecuador in techniques to effectively control the sand production and it is supported by an extensive amount of field data. The results obtained here have served to demonstrate that designs customized to fit specific reservoir conditions can help maximize the well's productivity and to optimize the completion costs.
Evaluation of the Relative Importance of Parameters Influencing Perforation Cleanup
Authors: Detwiler Russell L. , Morris Joseph P. , Karacan C. Ozgen , Halleck Phillip M. , Hardesty John 
Published: December 2007

AbstractCompletion of cased and cemented wells by shaped-charge perforation results in damage to the formation, which can significantly reduce well productivity. Typically, underbalanced conditions are imposed during perforation in an effort to remove damaged rock and shaped-charge debris from the perforation tunnel. Immediately after the shaped-charge jet penetrates the formation, there is a transient surge of fluid from the formation through the perforation and into the well bore. Experimental evidence suggests that it is this transient pressure surge that leads to the removal of damaged rock and charge debris leaving an open perforation tunnel.We have developed a two-stage computational model to simulate the perforation process and subsequent pressure surge and debris removal. The first stage of the model couples a hydrocode with a model of stress-induced permeability evolution to calculate damage to the formation and the resulting permeability field. The second stage simulates the non-Darcy, transient fluid flow from the formation and removes damaged rock and charge debris from the perforation tunnel. We compare the model to a series of API RP19B section 4 flow tests and explore the influence of fluid viscosity and rock strength on the final perforation geometry and permeability.
Dynamic Under Balanced Perforating Eliminates Near Wellbore Acid Stimulation in Low-Pressure Weber Formation
Authors: Stutz H. Lloyd , Behrmann Larry A. 
Published: December 2007

Abstract
Completions in the Weber formation have historically been perforated over balanced and then acid stimulated. Flow rates before acidizing were virtually 0 Mcf/D. Acid was an important step in the completion process. The Weber gas reservoir has low permeability (0.5 - 1.5 mD) and is now low pressure (2800 to 2300 psi at 14,000 ft). Typical flowing rates for these wells range from 1 to 5 MMcf/D. A new perforating technique utilizing the dynamic under balanced method was implemented in two wells, Brady 38W and Brady 56W. The wells were perforated with tubing-conveyed guns with initial over balances of 3250 and 3750 psi. The dynamic under balanced method creates an instantaneous under balance even though the annular space between the gun and the casing is initially over balanced. This perforating method also leaves significantly less perforation "skin." The proof is in the success of the two wells, which have rates equal to or in excess of the existing wells and yet required no acid stimulation. From historical comparisons of 18 prior completions, these wells should have had nearly zero flow without acid when perforating using an initial over balance of up to 3750 psi in the annulus. This paper discusses the new dynamic under balanced perforating design and its application to low-permeability, under-pressured reservoirs.
Benchmarking the Formation Damage of Drilling Fluids
Authors: van der Zwaag C. H. 
Published: December 2007

AbstractThe "Unified test protocol for laboratory formation damage assessments" consists of functional procedures that attempt to standardise formation damage service projects. Setting functional requirements was preferred above detailed instructions with respect to laboratory work processes and the handling of laboratory equipment.In order to assess the formation damage potential of a fluid for drilling or well operations, three sections of the protocol need to be accomplished. These are respectively: "Information", "Simulation" and "Analysis".This paper presents the three sections of the unified protocol and discusses the effect of the functional approach. Special emphasis is put on a distinction between well fluids that experience dynamic and static filtration regimes, as these require different ways of simulating fluid applications to the rock sample. To provide engineering parameters relevant at field scale and to identify the full range of potential formation damage mechanisms that may affect the reservoir, analyses on "centimeter", "millimeter" and "micrometer" scale are suggested.Minimum requirements to upscale formation damage measurements to field scale are presented. We also present an option for full scope "diagnostic" formation damage assessments.Applications of numerical models that have been suggested in earlier research yield "return permeability", "filtrate invasion depth", "lab skin", "efficiency of flow" and "loss of revenue" as parameters to benchmark the formation damage of well fluids.
High-Permeability Fracturing: "Carter" Fluid Loss or Not
Authors: Smith Michael B. , Bose Michael , Klein Henry H. , Ozenne Brent R. , Vandersypen Ron S. 
Published: December 2007

AbstractFrac-packs, and hydraulic fracturing, have become accepted, successful completion procedures for high permeability formations. To some extent, this success has come despite less than full understanding of the processes. Statements such as "fracture models cannot predict net pressure behavior in soft rocks" are heard. Inconsistencies are blamed on radical departures from "classical" theories of fracturing, and in some instances, this may be warranted. However, it is best to first examine simpler possibilities (Occam's Razor). Radical departures should not be postulated until fracture models routinely address actual geologic/reservoir environments.What is the big difference for high permeability fracturing? Of course, it is not "soft" rock, it is permeability, thus, fluid loss. ALL fracture designs are based on the idea of 1D, i.e., Carter or C/ t, loss, and assume (with no justification) this is valid. High loss is accounted for by high fluid loss coefficients, but using high values for something does not describe the process. One possible cause of the inconsistency might be non-1D, i.e., non-Carter type, loss behavior.Non-1D fluid loss occurs in water injection/water disposal fractures (though "normal" fracture models are still mistakenly utilized in these situations). 1D loss is valid if the fracture propagation is greater than loss velocity, and this condition is NOT true for water flood induced fracturing. Is this true for high permeability fracturing - with fluid efficiency &lt; 10%, even in propped fracturing treatments using viscous fluids?This paper examines this question using a coupled 3D fracture-reservoir model (as described in Appendix A) to accurately simulate fluid loss. We simulate several field cases, review the design/post-analysis based on "traditional" loss behavior, and examine the effect of rigorously simulating loss. The results are used to identify conditions where non-Carter fluid loss is significant, and how to modify designs appropriately.
Development of a Novel Alcoholic Acid System for Removal Damage Resulting from Hydraulic Fracturing in the Tight Gas Reservoir
Authors: Wang Xugang , Zou Honglan , Chen Yandong , Zhang Fuxiang , Peng Jianxin 
Published: December 2007

Abstract
This paper presents a novel alcoholic acid system to remove the damage caused by frac fluid in tight gas reservoir. Damage resulting from hydraulic fractures takes two distinct forms: damage inside the fracture itself because of inadequate breaking of the fracturing fluid polymer; and fracture-face damage because of excessive leak-off. The objectives of laboratory experiments are to identify potential damage and aid selection of the optimum treatment fluid and design. A novel alcoholic acid flow tests illustrated the permeability increased because of pore & throat enlarged by using mercury intrusion experiments. It was critical in addressing issues of selection of fracturing fluids, polymer concentrations and breakers. Improved breaker systems show even greater benefit when used in conjunction with the lower loading polymer systems. The newer fluid systems enhance load recovery and reduce formation exposure to potentially damaging polymer residue.
DB gas reservoir is a low porosity, low permeability reservoir in the northwest of China. Large scale of hydraulic Fracturing has been carried out as effective method to get high gas production rates. However, the gas production rate after treatment increased to 335,683m3/d, and then declined to 34,875m3/d rapidly. The skin factor from well testing after hydraulic fracturing was 112, which indicated fractures and formation may appear damaged seriously because of more than 60% of the load fluid can be invaded and trapped in the formation by entering the smaller capillary pores during higher injection pressures. The gas production rate recovered from 32,383m3/d to 301,374m3/d and kept constantly by using treatment method of a novel alcoholic acid system.