bluuebunny/crossref_metadata_2025_split huggingface dataset:
Injectivity of Frac-Packed Wells: A Case Study of the Guando Field
Authors: Suri A. , Sharma M. M. , Moreno J. M. 
Published: February 2010

Abstract
The Guando field in Colombia, South America, is a sandstone reservoir with an initial pressure about 150 psi at GOC. A waterflood has been implemented since early in the life of the field. A complete set of data has been maintained on each of the injectors since 2002. This data set includes: daily injection rates, pressures, water quality and solids analysis. Injection into four different hydraulically fractured reservoir units is controlled by down-hole valves. In some cases wells are operated at injection pressures above the fracture gradient.
To ensure good reservoir sweep efficiency, waterflood control and assurance of injectivity for each reservoir unit a detailed study of the injectivity of each injector was undertaken to understand the possible growth of fractures and its impact on frac-pack injectivity, injection profile and oil recovery. Field data indicates that the quality of river and produced water streams, mechanical configuration, stimulation of injector wells and injection facilities are important parameters that control the injectivity behavior.
Injection well simulations are presented to show that the injectivity behavior can be history matched quite well and this process provides valuable insight into the dependence of injection parameters such as injection rate and water quality on injection profiles and fracture growth. This paper presents data and history match simulations for seven injectors from the field. The results allow us to estimate the fracture lengths that are created in the injectors and to thereby evaluate the effectiveness of injection schemes being implemented. This history match study allowed us to make recommendations for future injection rates and water quality into each of the injectors.
To the best of our knowledge this is the first time that the injectivity of multi-layered, frac-packed injectors has been history matched with field data over an extended period of time. These history matched results validate our injection well model for frac-packed injectors and provide important guidance on future injection well design in addition to making concrete recommendations for the Guando field.
Achieving Successful Diversion in Acid Stimulation Treatments: Case Study of Excellent Results Achieved Using Associative Polymer Treatment (APT) in Highly Heterogeneous Carbonate Reservoirs in Saudi Arabia
Authors: Nunez-Garcia W. , Leal-Jauregui J. , Malik A. , Solares J. R. , Al-Abdulmohsen Y. , Al-Mumen M. , Izquierdo G. 
Published: February 2010

AbstractAn effective diversion technique is a critical component in all acid stimulation jobs, which enables us to achieve full zonal coverage and thereby achieve the treatment objectives. The highly heterogeneous multilayered nature, and the high temperature and pressure condition of the carbonate reservoirs in the Saudi Arabian gas fields, pose a significant challenge in the ability to achieve effective diversion.Associative polymer technology (APT), which is a very low viscosity aqueous-polymer solution designed for optimum diversion was successfully field tested during acid matrix treatments pumped in three new gas producers. The treatments comprised an organic acid blend, retarded acid and associative polymer diverting fluid, and were pumped in perforated intervals up to 264 ft. The diversion and acid reaction signatures were clearly shown in the acquired surface and bottom-hole pressure (BHP) plots for all respective stages, thereby indicating a successful diversion. A post-stimulation pressure buildup (PBU) test conducted in one well showed a skin of -4. Production testing (PLT) surveys conducted in two of the treated wells showed flow contribution from all targeted pay zones, and a net gas rate gain of up to 40% was recorded.This paper will discuss the rationale for selecting APT, acid fluid design and optimization, treating pressure behavior, and post-treatment results and diagnostic data, which confirm the effectiveness of the associative polymer as a diverting agent.
Results From Acid Stimulation in Lloydminster SAGD Applications
Authors: Brand S. 
Published: February 2010

Abstract
SAGD (Steam Assisted Gravity Drainage) thermal production of heavy oil in the area surrounding Lloydminster involves the injection of steam and subsequent pressurization of the reservoir. As fluid enters the horizontal producer, the pressure drop results in the deposition of calcium carbonate scale. Scale deposition eventually begins to have a detrimental effect on fluid inflow into the wellbore. In addition to the calcium carbonate scale, the high ashphaltene content of the oil results in a hydrocarbon coating being deposited on the scale. Many options exist to remove the scale/ashphaltene deposit and return the well to prior oil production rates. This paper will review the mechanism believed to cause scale deposition, available chemical and mechanical methods to remove the scale and Husky’s recent successes from treatment of SAGD wells in a sandstone reservoir in the Lloydminster heavy oil area.
Determining the Best Diversion Methods for Tight Gas Sand Stimulation
Authors: Wei Y. N. , Cheng K. , Ogueri O. S. , Holditch S. A. 
Published: February 2010

Abstract
Producing natural gas from Tight Gas Sand (TGS) reservoirs is currently very important to the industry in North America and will be of increasing importance to the global energy industry in the coming decades. Many wells are completed and drilled each year in thick, tight gas reservoirs that have many individual layers that can contribute to production if adequately perforated and stimulated. It is important to select a diversion technique that allows access to the most layers with the most gas in place at minimal costs. However, we have found essentially no papers in the petroleum literature that provide a logical method for selecting the best diverting method for a given set of reservoir conditions. There are papers that discuss successful field cases where specific diversion methods seem to work for specific reservoirs. We have used many of these SPE papers to help define "best-practices" concerning the selection of diversion technologies in completing tight gas sands with thick, multiple pay zones. We then developed logic to give advice to the user on the best diverting methods for specific reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing methods for diverting fracture treatments.
The effort to develop a model to determine the best diversion methods is part of our effort to build software that we call TGS Advisor. TGS Advisor can be used to provide advice to engineers developing TGS reservoirs. The program can be described as an "Advisory System". The user enters the reservoir data that are known and the program provides advice on how to drill, complete and stimulate the reservoirs identified in the well. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build the TGS Advisor program. We evaluated the results of the advisory system with published case histories in the SPE literature. We have included examples of how TGS Advisor can help the user to determine appropriate diversion technologies for given reservoir conditions.
Wormholing in Perforated Completions
Authors: Kalia N. , Balakotaiah V. 
Published: February 2010

Abstract
Matrix acidizing of carbonates is routinely carried out to increase hydrocarbon production rates from a reservoir. This involves pumping acid through the wellbore into the formation where it reacts with the rock and results in an increase in permeability. As a result of the dissolution reaction, different types of dissolution patterns are created. These patterns depend on the injection rate, type of fluid, rock mineralogy, temperature, flow geometry, etc. The effect of these factors on dissolution patterns has been studied extensively in the past. However, most of the reported experimental and theoretical work presents wormholing under openhole conditions. When the well completion includes perforated casing, fluid-flow through the perforations is markedly different from that in an openhole completion. The degree of success of an acid job in a perforated completion is limited by the proximity of the damage to the perforation tunnel. The wormhole pattern structure, penetration distance, and acid volume required to achieve a given permeability increase in such a completion is still not clearly understood.
In this paper, the effect of injecting acid into a rock sample through perforations is studied by using a two-scale continuum model. The model represents the complex coupling between flow, transport, and reaction of acid in a carbonate rock. Two-dimensional simulations of the model show the flow redistribution inside a rock sample when acid is injected through a constriction. It is shown that the amount of acid required to achieve a given permeability (or, wormhole-penetration distance for a given volume of acid) depends on both perforation and sample dimensions. Conditions under which maximum skin decrease is observed are also identified. In addition, the main differences in predictions from perforated and openhole completions are highlighted.
Because a substantial number of current carbonate well completions are cased and perforated, it is important to understand matrix acidizing under such conditions. Particular application from this work includes better matrix-acid treatment designs with optimum acid volumes and rates.
The Evolution of Sand Control Completion Practices for the Enfield Deep Water Development
Authors: McCarthy T. A. , Mickelburgh I. J. 
Published: February 2010

Abstract
The Enfield development was the first oil field to be put into production in the Greater Enfield Area. These fields lie in deep water off the North West Cape area of Western Australia. Operated by Woodside on behalf of the Enfield Joint Venture, this was the first oil field development for Woodside requiring horizontal open hole completions with sand control. The challenge for this project was to deliver early oil production from a low well count with wells producing from an unconsolidated and faulted formation containing shale. The remote location posed an additional challenge for the development.
The initial development consisted of 5 producers, 6 water injectors and 2 gas disposal wells, with subsequent campaigns adding 3 production well sidetracks, a new producer and a water injector to the total reservoir penetrations. Both low angle deviated and horizontal wells have been completed. A number of different sand face completion types have been used over the initial phases of the Enfield development. Both water and oil based reservoir drilling fluids were used for this field development. This paper will review the evolution of the design used for the production wells.
Initial horizontal gravel packs were done with a circulating gravel placement technique using brine as the carrier fluid. Subsequently a single barrier sand control technique using expandable screens alone to control sand production was installed. Due to difficulties encountered with these approaches, completion designs reverted to gravel packing. However at this second attempt at gravel packing, a gel slurry packing technique using screen fitted with alternative paths for gravel placement was successfully used.
Whilst deep water open hole gravel packing was a new challenge for Woodside; due to the high productions rates achievable, only a limited number of wells were required for the field development. This implied both a very short learning curve, and a need to react rapidly to any difficulties encountered. This paper reviews the performance of these completions and the drivers for the evolution of the completion technology during the field development. This has provided a pathway for future completions in the development of similar reservoirs in the portfolio.
Formation Damage in Gas Storage Wells
Authors: Barker K. M. , Germer J. W. 
Published: February 2010

Abstract
Natural gas has to be produced, transported and stored until it is needed by the eventual consumer. The gas is most commonly held in inventory underground under pressure in three types of facilities: (1) depleted reservoirs in oil and/or gas fields near the regional end markets, (2) aquifers, and (3) salt cavern formations.
Each type of gas storage field has its own unique set of physical characteristics (porosity, permeability, retention capability) and economics. The most important characteristics being the formations ability to hold natural gas as needed (volume, integrity and injectivity) and the rate at which it can be withdrawn (deliverability).
Studies have shown that with time, the repeated high-pressure injection and withdrawal of gas progressively damages gas storage wells by filling the permeability with inorganic precipitates, hydrocarbons, organic residues, production chemicals, bacterial fouling, emulsions, water blockages and naturally-occurring particulates. Many of these types of damage do not respond to normal acid stimulation treatments which are still being done at a cost of over $100 million to the gas storage industry.
This paper will discuss the types of damage, methods of removal and will include a case history of a new type of treatment to remove the specific types of damage being experienced in one aquifer gas storage field and the economic benefit experienced in that field.
A Laboratory Investigation of the Factors Controlling the Filtration Loss When Drilling With Colloidal Gas Aphron (CGA) Fluids
Authors: Bjorndalen N. , Jossy W. E. , Alvarez J. M. , Kuru E. 
Published: February 2010

Abstract
The colloidal gas aphron (CGA) drilling fluids are designed to minimize formation damage by blocking pores of the rock with microbubbles and reducing the filtration loss.
In order to gain a better understanding of the factors controlling the pore blocking mechanisms of microbubbles, a set of core flooding experiments were conducted by using various CGA drilling fluid formulations. The differential pressure drop along the sand-pack was measured.
Effects of CGA fluid composition, flow rates, type of reservoir saturating fluids, permeability and wettability on the resistance to CGA drilling fluid flow through porous media (i.e., pressure drop due to CGA fluid flow) have been investigated.
An increasing resistance to flow of CGA drilling fluids through porous media was observed as more CGA fluid was injected. Results confirmed that CGA microbubble build-up across the pore structure could establish an effective seal for controlling filtration loss.
Acid/Scale Inhibitor Stimulation Treatment for High-Temperature CHFP Subsea Wells: Fluid Qualification and Formation Damage Assessment
Authors: Marquez M. , Wetzel R. J. 
Published: February 2010

Abstract
Cased Hole Frac Packs (CHFP) are among the preferred completion strategies for deepwater production wells due to sand production concerns and the high cost associated with subsea interventions. An acid stimulation treatment is usually conducted prior to the main frac operation in order to clean-up some of the perforation debris (including powdered metals from shaped charges) and residual fluid loss control (FLC) materials which can be a significant source of formation damage and plugging of screens and other wellbore jewelry. A few studies have also considered the technical and economical benefits of adding a scale inhibitor during the completion operation (Fitzgerald and Cowie, 2008; Lungwitz et al. 2007; Martins et al., 1992; Vetter et. al., 1988). The challenges associated with adding a scale inhibitor to the frac fluids are widely recognized, and some alternatives such as the use of encapsulated scale inhibitors and scale inhibitor-impregnated proppant have been proposed (Powell et al. 1995; Fitzgerald and Cowie, 2008). The addition of scale inhibitor to the early stages of the frac operation has also been explored (Maschio et al., 2007), but the temperature ranges evaluated have been rather limited. The purpose of this work is thus twofold: 1) To evaluate the effectiveness of two acid suites to clean-up Zn powder damage typically encountered during perforations with metal shaped charges, and 2) To qualify the incorporation of an acid pentaphosphonate scale inhibitor to the pre-frac acid in frac treatments targeting high temperature (up to 300°F) deepwater subsea wells. This paper describes in detail the laboratory qualification of the acid suite, and the acid / scale inhibitor combination treatment. Performance field data on the treatments is the subject of subsequent publications.
A HCl / organic acid suite with a novel, three-component corrosion inhibitor package was developed to clean-up Znrelated damage without compromising rock strength or corrosion protection at high temperatures (up to 300°F). In addition, the combination treatment consisting of scale inhibitor treated acid and overflush brine was found to be compatible with reservoir and wellbore fluids in the field of interest. The treatment was found to be non-damaging in high permeability (&gt; 1000 md) Y core samples. Strong wettability changes and up to 50% reduction in permeability to oil were observed in low permeability X core samples. Further improvement of the acid / scale inhibitor combination treatment for low permeability reservoirs is also discussed. The results from this study contribute to a better understanding of scale management in high temperature subsea wells.
Laboratory Evaluation of RDF Breakers Under Linear and Radial Flow Conditions
Authors: Marquez M. , Lenz R. 
Published: February 2010

Abstract
Drilling-induced formation damage is an area of concern when it comes to wellbore productivity, particularly for highly deviated / horizontal open hole completions. A great deal of effort has been devoted to understanding the damage mechanisms associated with Reservoir Drill-in Fluids (RDF), and to develop systems to specifically target bio-polymers and bridging agents in the RDF cake for improved wellbore clean-up. Experimental techniques to evaluate the performance of RDF clean-up treatments, however, have not received much attention. Due to its simplicity, the High Temperature High Pressure (HTHP) cell has been widely adopted by the Industry as a standard method to evaluate the performance of RDF filter cake stimulation treatments, but this technique has a number of limitations in terms of the quality and reproducibility of the deposited filter cake, as well as its ability to predict flow initiation pressure and return to flow percentage after the stimulation treatment.
This work compares the performance of two commercial RDF breakers in a GP application, under linear and radial flow conditions, using a HTHP cell and the Dynamic Displacement Radial Permeameter (DDRP) device described by Davidson et al. (2006). Unlike the HTHP cell, the DDRP cell can be arranged such that the RDF deposition, displacement, and stimulation stages of a horizontal Open Hole Gravel Pack (OHGP) can be simulated dynamically and sequentially, without system disruptions. The breakers evaluated are combinations of polymer-specific enzymes, chelating agents, and acid. Breaker "A" is a buffered acid system, while Breaker "B" contains a slow release acid precursor. The clean-up efficiency of each breaker, relative to a control system with no breaker, was determined as a function of flow rate using the DDRP device. These results were compared to those obtained under linear flow conditions with the HTHP cell. Significant differences were observed between the flow initiation pressure values measured with the HTHP cell and those measured with the DDRP, particularly for the system with no breaker. Differences were also observed in terms of percentage return to flow; higher percentages were consistently measured with the DDRP device. The difference between the percentage return to flow measured with the HTHP cell and the DDRP device was less than 5% for the system with no breaker, and 20% to 55% for the systems treated with the breaker solutions. In general, linear flow tests with the HTHP cell are useful as a pre-screening tool, but more sophisticated equipment such as the DDRP device can simulate downhole flow patterns and cake deposition more accurately and reproducibly. They also provide insight to important design parameters such as breaker activation time and flow rate dependencies of the clean-up treatment.
A Novel Technique for Achieving High Rate Water Injection at Matrix Rates In Openhole Sand Control Completions: A Case History from Akpo Field, Nigeria
Authors: Marpaung Fivman , Bourgoin Sebastien , Bagal Joseph , Deffieux Damien , Beldongar Maye , Patey Michael , Gadiyar Bala , Parlar Mehmet 
Published: February 2010

Abstract
Many of the water injectors in sand control environments are being completed as long open holes due to higher injectivities attainable with such completions. Although target rates may often be achieved without any cleanup chemicals in production wells, injection wells require filtercake cleanup, in cases whereproducing the well prior to injection is not feasible or desirable, (e.g., limited storage capacity on the rig, or artificial lift requirements due to low pressure or injection into water leg)injecting above frac pressure is either not feasible (e.g., very high frac pressures and pump limitations) or not acceptable (e.g., sweep efficiency, premature water breakthrough, uncontrolled fracture height growth).
Although a large variety of filtercake cleanup techniques and chemistries are available in the industry, most of these solutions are effective in producers. As demonstrated through laboratory experiments, achieving consistently high injectivities requires removal of drill solids from the filtercake, through either dissolution (e.g., acid formulations utilizing HF) or effective displacement techniques that will not result in injection of these solids into the formation pore throats (SPE 77449). In addition, an effective filtercake removal (including drill solids) in long open holes without inducing high losses into the formation (so that the wash pipe can be pulled out and a mechanical fluid loss control valve can be activated) remained as a formidable challenge, which becomes even a bigger challenge in wells drilled with conventional oil based muds (OBM), particularly in reactive shale environments.
In this paper, we present a novel technique that addresses these challenges, proven through field application on a standalone screen water injector in Nigeria. The technique involves displacement of OBM from openhole with a viscous spacer pill containing a demulsifier, followed by completion brine containing a mutual solvent to weaken the filtercake without attacking the bridging agents, subsequently performing a high rate viscous pill displacement to remove the external cake, and finally spotting a water-based self-destructive fluid loss control pill to control the losses while pulling the wash pipe. Laboratory testing for designing the displacement stages, field execution, and well performance evaluation are detailed.