bluuebunny/crossref_metadata_2025_split huggingface dataset:
Equalization of the Water Injection Profile of a Subsea Horizontal Well: A Case History
Authors: Amaral Anderson da S. , Augustine Jody , Henriksen Knut , Rodrigues Valdo Ferreira , Steagal Daniel Escobar , Paixão Luiz Carlos Alves da , Barbosa Pereira 
Published: February 2008

Abstract
This paper focuses on the first global installation of a water injector well with a lower completion system that incorporates both premium sand control screens and water injection profile equalization. The equalization of the water injection profile of horizontal wells has been a key issue in many development projects worldwide and has the potential to increase the reservoirs ultimate recovery by increasing the water sweep efficiency.
Inflow Control Devices integrated with premium sand control screens have a long history of application in production wells. In these cases the main objective is to create a uniform inflow profile along the horizontal section, delaying unwanted water and gas production and increasing oil recovery. The method through which Inflow Control Devices equalize the inflow of oil can also be used to equalize the outflow of water. Historically, sand control completions for water injection wells include stand-alone conventional screens and open-hole gravel packs. Stand-alone conventional screen completions do not provide equalization of the water injection profile. Open-hole gravel packs provide for an effective acid treatment of the water injector well but present operational risks, high costs, as well as expensive rig time.
The installation was carried out in a subsea horizontal sea water injector well in the Campos Basin, offshore Brazil. The paper presents the overall completion plan, the lower completion installation, the acid treatment through the Inflow Control Devices, and the initial water injection results based on production logs and water injectivity tests. The main concerns during the planning phase are discussed, highlighting the procedures adopted to overcome them.
The good initial results have created the expectation of many applications of this system in Campos Basin. It is believed that sharing this information will benefit many operators with horizontal water injectors in their field development plans.
New Agent for Formation-Damage Mitigation in Heavy-Oil Reservoir: Mechanism and Application
Authors: Wang Y. , Kantzas A. , Li B. , Li Z. , Wang Q. , Zhao M. 
Published: February 2008

Abstract
Migration of formation fines has been shown to cause production decline in many wells, especially for sand production wells in heavy oil reservoir. Filter cakes in wire wrapped liner, which were formed by the attachment of viscous crude oil blended with formation fines, may block the flow paths of viscous oil. The solution to this problem is appropriate treatment to mitigate this type of formation damage.
In this paper the performance at laboratory-scale of a new type of agent for formation damage mitigation is presented and some guidelines for its application including the injected pore volume and injection concentration are provided.
The mechanism for damage mitigation with this type of agent in heavy oil reservoir was introduced in detail, it mainly include that this type of agent can reduce interfacial tension between crude oil and water and change the wettability of rock surface, which may lead to the breakaway of resins and asphaltenes attached to the rock surface.
By simulation experiments and core flood tests the effectiveness of this type of agent to mitigate the damage in heavy oil reservoir was identified. Simulation experiment results show that, damage mitigation in cores with the permeability higher than 1μm2, is more effective than those with the permeability lower than 1μm2, and core flood experiment results also indicate that this type of agent with the concentration of higher than 5% can remarkably increase recovery factor for cores with the permeability higher than 1μm2. Finally some results on the behaviour of its application in heavy oil reservoir are presented.
An Experimental Investigation of Drilling-Fluid Filter-Cake Removal by Acid Jetting
Authors: Mikhailov M. , Zhu D. , Hill A. D. 
Published: February 2008

Abstract
Acid jetting from ports near the end of a tubing string is a common method being applied to remove drilling or completion fluid filter cakes and to stimulate near-wellbore permeability. To be effective, the acid jet must remove enough of the filter cake to eliminate any significant filter cake Δp, and should stimulate some distance into the formation if internal damage has occurred. In this study, we experimentally evaluated the efficiency of acid jetting at conditions similar to those being applied in the field. The results obtained with acid jetting were compared with those obtained jetting with water alone to determine the relative importance of the mechanical removal of the filter cake by the liquid jet and the dissolution of filter cake and formation solids by the acid.
We first created a drilling fluid filter cake and internal damage by circulating a typical drill-in fluid containing sized CaCO3 particles past the face of a 4-inch diameter by 18-inch long core for up to 18 hours. A pressure differential of 500 psi was held across the core to drive filtrate and possibly solids invasion into the rock. Acid (15% HCl) was then jetted from a small port on to the center of the core face at velocities typical of field applications. The velocity and duration of jetting was varied systematically in the experiments. In each experiment, we measured the evolving permeability of the filter cake/core system by measuring the pressure drop across the system.
In this paper, we show how the key parameters of jet velocity and duration of jetting affect jetting efficiency. Comparison of the acid jetting results with those obtained jetting with water alone show how much of the cleanup is accomplished by the mechanical action of the liquid jet compared with the chemical dissolution of the solids by the acid. In many cases, the jetting action provides the primary restoration of productivity with less effect caused by acid dissolution.
Well Stimulation and Gravity Segregation in Gas Improved Oil Recovery
Authors: Jamshidnezhad M. , Chen C. , Kool P. , Rossen W. R. 
Published: February 2008

Abstract
Models for gravity segregation in gas improved oil recovery (IOR) indicate that the distance injected gas and water travel together before complete segregation scales with the injection rate Q. Therefore, in cases where injection pressure is limiting, reducing skin resulting from damage at the wellbore face directly increases volumetric sweep of gas in IOR. Even in the absence of damage at the wellbore face, most of the injection pressure is dissipated near the well, but most of the segregation occurs much further from the well. Therefore, if injection pressure is limited, increasing mobility near the injection well has a large impact on Q, with a direct benefit in delaying gravity segregation. There is also a relatively small increase in gravity segregation in the near-well region. An analytical model for gravity segregation in homogeneous reservoirs can be extended to a case where permeability is stimulated within a cylindrical region inside a larger cylindrical reservoir. The effect of this stimulation in increasing Q at fixed injection pressure can be estimated as well. One can increase the volume swept by gas before segregation by as much as 170%, though a large volume must be stimulated to reach this optimum.
The model represents schematically a number of ways proposed in gas IOR for delaying segregation beyond the possibilities with uniform, steady co-injection of Newtonian fluids: alternate injection of gas and liquid (WAG, or SAG with foam); injection of gas above water; and injection of shear-thinning foam. In all these cases the process gives higher mobility near the well, allowing an increase in injection rate, and thereby increases the distance to the point of segregation.
The model can be extended directly to the case of shear-thinning (power-law) foam. One obtains a differential equation for the segregation process, in place of the algebraic equation that results for Newtonian fluids. In the limit of extremely shearthinning behavior, it is possible to double the distance to the point of segregation with no increase in injection pressure. Simulations fit the theoretical prediction well.
Method to Pump Bridge/Frac Plugs at Reduced Fluid Rate
Authors: Smith Don , Starr Phillip 
Published: February 2008

Abstract
This case-history paper presents hardware and a method to enable pumping frac plugs and bridge plugs into horizontal wells, using substantially less fluid than used by conventional pumpdown means. Cases presented are from operations in the Barnett Shale formation of north Texas.
The system presented was developed in response to (1) the need to conserve well fluids used and (2) high pumping rates needed to pump frac plugs and bridge plugs to setting depths in horizontal holes. Fluids bypassing the plug without exerting enough push on the plug necessitated application of high pump rates and total fluid volumes.
Advantages of (1) using new sealing methods to reduce fluid requirements, and (2) following a set of procedures to pump plugs to the setting depth in horizontal wells are numerous: Total volume of water needed is greatly reduced.Lower pumping rates allow for the use of wireline when tight formations are encountered.Precludes the requirement to bring in more expensive and time-consuming methods of placing the plugs to depth, such as hydraulic tractors or coiled tubing units.Saves time and fluid costs.Reduces chances of damaging reservoirs with excess pumpdown fluid.Fluid flow around the sealing device provides a jetting action ahead of the tool to disperse sand and debris ahead of the plug in horizontal casing, based on field experience.As compared to that of hydraulic tractors, the system enables high travel rate for wireline, up to 150 ft/min.
The paper presents procedures for running plug-sealing devices that reduce the bypass of fluid between the plug and casing wall. The system has been in use for about 1 year; field experience, lessons learned, and application tips are also presented.
Radial Profiling for Completion Effectiveness With New Sonic Measurement in the Gulf of Thailand
Authors: Jiang Long , Schilling Keith , Logan Jim 
Published: February 2008

Abstract
Acoustic measurements have long been used to evaluate rock properties in the near-wellbore region and these methods are well documented. Comprehensive characterization of the wellbore rock relies on the knowledge of compressional and shear slowness in the axial, azimuthal, and radial directions. A recent evaluation in the Gulf of Thailand demonstrates that an understanding of the radial variations may prove extremely valuable in our understanding of completion effectiveness and may provide further insight into changes required in drilling practices or drilling fluid management. Acoustic variations in the near-wellbore region can arise as a result of nonuniform stress distributions, mechanical or chemical near-wellbore alteration from the drilling process, and formation intrinsic anisotropy related to in-situ properties of the formation. This document will explore results from acoustic measurements and interpretation of the near-wellbore resulting in operative information. Combined with measurements of formation properties this information can provide an accurate assessment of the drilling environment and the reservoir. This knowledge can lead to reduced overall drilling costs, improved recovery, and productivity.
Sanding Study for Deepwater Indonesia Development Wells: A Case History of Prediction and Production
Authors: Palmer Ian D. , Higgs Nigel G. , Mathers Robert M. , Herman Scott R. 
Published: February 2008

Abstract
A detailed sand prediction has been made for three wells at Chevron's West Seno field based on logs/lab data and the results have been calibrated with production data. Both maximum allowable drawdown and depletion increase with depth. Additionally, oriented perforations offer an improvement to perforation stability against sanding: the maximum allowable drawdowns and depletions are increased for all sands. Finally, an analysis is presented on the economics and trade-offs of vertically-oriented perforating (with possibly managed sand production) versus frac-packing. Sand onset prediction agrees fairly well with the observed drawdown/depletion for horizontal perforations. This benchmarking appears to support the validity of the shear-failure model. This is important because the model, while fairly simple, has many different inputs, including depth profiles for unconfined compressive strength (UCS) and in-situ stresses, which involve sophisticated prediction techniques themselves. Continuous sand rates (for oil wells) have also been predicted by extending the shear-failure sanding model. As depletion increases over time, added perforation intervals begin to fail/collapse, increasing the sand rate. There are periods of agreement and underestimation (by a factor of ~4) between observation and prediction. This is important because it is the first time this model has been benchmarked against observation at early times in a well's life. It appears the model can provide a first estimate of sanding levels in oil wells, which are useful to assist the design of well facilities for dealing with sand. Finally, a sand prediction was used to evaluate oriented perforating in lieu of frac-packed completions. The evaluation defined production scenarios, by building nodal and production forecast models, and ran incremental economics. It indicated that oriented perforating can provide favorable economics over frac-packs if critical rock properties and production plans are defined and understood.
Experience With Chemical Sand Consolidation as a Remedial Sand-Control Option on the Heidrun Field
Authors: Haavind F. , Bekkelund S. S. , Moen A. , Kotlar H. K. , Andrews J. S. , Håland T. 
Published: February 2008

Abstract
The Heidrun field located in the Norwegian Sea is an oil and gas producing field which has been developed with a tension leg platform (TLP) installed over a template with 56 slots. Two subsea production templates and three subsea water injection templates are also tied back to the TLP. All wells require sand control measures in the reservoir section to prevent sand production. The sand control philosophy has gradually evolved from cased hole gravel packs, through stand alone screens to todays preferred option of openhole gravel packing. Sand control in the field is challenging with high fines content in the reservoir and a potential for plugging from scaling from secondary recovery with seawater. Sand control integrity has failed in some wells and offtake rates in these wells are limited to Maximum Sand Free Rates (MSFR). In some cases intervention is required for remedial sand control or new sidetracks are planned. However, for a number of suitable wells, chemical treatments that consolidate the near wellbore area can be a viable alternative to improve well offtake rates.
The chemical treatment is mixed in diesel and bullheaded in the well. The active chemical will react with the connate water in the near wellbore area and form a polymerized network which binds the sand grains together. In that way, the residual strength of the formation is increased and can withstand larger hydrodynamic forces before the grains are transported into the wellbore.
To date three Heidrun wells have been treated with the sand consolidating chemical that has been developed in-house. Two of these are platform wells and the third is subsea. One of the platform wells has been retreated twice following a successful first treatment. This work describes the five different treatments; the planning, the execution and the post-job analysis. One of the treatments was not successful, another one was very successful. The reasons behind these results will be discussed.
Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan
Authors: Arangath R. , Hopkins K. W. , Lungershausen D. , Bolyspayev N. T. 
Published: February 2008

Abstract
Stimulation of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity, damage to each zone, matrix mineralogical composition, and pressure regimes of each zone need to be taken into consideration. The presence of natural fractures makes the entire treatment more complex.
Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor to the lowest possible value in each zone. At the same time, the selected optimum acid system, placement, and diversion techniques need to be applicable in the field in a simple manner without impacting the overall treatment logistics.
The use of a hydrochloric acid system containing a viscoelastic surfactant system that allows, upon acid spending, the development of viscosity in situ, has shown that significant skin reductions can be obtained provided the proper placement techniques are used. However, in certain cases where natural fractures are dominant, diversion effects can be noticed but are not optimal. An enhanced system that contains temperature-degradable fibers has been used in Kazakhstan. Such systems are shown to successfully divert and stimulate effectively even when natural fractures are dominant.
This paper presents experiences with different types of acid placements and diversion techniques in the thick carbonate reservoirs of western Kazakhstan. Pretreatment and post-treatment production data have been analyzed to evaluate the effectiveness of the treatments in terms of skin reduction or productivity index increase.
Formation Damage Induced by Various Water-Based Fluids Used to Drill HP/HT Wells
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Bataweel M. A. , Al-Majed A. A. , Menouar H. 
Published: February 2008

Abstract
Drilling Unayzah-B reservoir (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf) to mechanically stabilize the shale and balance the reservoir pressure. Two fluids are used to drill this reservoir: KCl/ BaSO4/ CaCO3 whereas the second is potassium formate/CaCO3. Barite is added with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, BaSO4 is insoluble in acids and requires chelating agents to remove it from the formation. Formate drill-in fluids with low solid content can then be used, but they are expensive and corrosive at pH values less than 7-8. To overcome some of the problems associated with these two systems Saudi Aramco developed water-based drill-in fluids using Mn3O4. No similar formulations were developed before to the best of the authors' knowledge.
The objective of this study is to determine formation damage induced by KCl/Mn3O4 mud at 95 pcf. A mini-flow loop was used to assess formation damage induced by the three the drill-in fluids. The experiments were conducted using reservoir cores at bottom hole conditions. Another set of experiments were conducted using a dynamic HPHT cell to determine the thickness and composition of the filter cake filter cake, spurt loss and chemical analysis of filtrate. Compatibility tests between mud filtrate and produced water were performed at 300 °F and 500 psi using see through cells.
The KCl/Mn3O4 showed the least formation damage compared to the other two fluids. The return permeability was significantly higher than those obtained with potassium formate/CaCO3 or BaSO4/CaCO3 mud systems. Potassium formate filtrate was not compatible with Unayzah-b formation brine, which resulted in its low return permeability (42%) in spite of its low solids content. Unlike formate based fluids, mud filtrate of KCl/Mn3O4 was compatible with the formation brine. BaSO4/CaCO3 drill-in fluid resulted in 40% because the barite solids were trapped inside the core. KCl/Mn3O4 drill-in fluid resulted in 70% return permeability. The main reason for this high result is the spherical shape and small size of Mn3O4 particles, which allowed them to be removed by flow of hydrocarbons.
Characteristics and Removal of Filter Cake Formed by Formate-Based Drilling Mud
Authors: Al Otaibi M. B. , Nasr-El-Din H. A. , Hill A. D. 
Published: February 2008

Abstract
Formate-based mud has been used to drill deep gas wells in Saudi Arabia since 2004. This mud typically contains XC-polymer, starch, polyanionic cellulose, and a relatively small amount of calcium carbonate particles. This mud (typically 90 pcf, pH of 10) is used to drill a deep sandstone reservoir (310°F). Various cleaning fluids were proposed to remove drilling mud filter cake; including: solids-free formate brine, formate brine doped with organic acids (acetic, formic, citric, and lactic acids), and enzymes. The main objective of this paper is to assess the effectiveness of these cleaning fluids in removing formate drilling mud filter cake.
A dynamic HPHT cell was first used to determine characteristics of the formate mud filter cake. Drilling mud and completion fluids were obtained from the field. The experiments were conducted using ceramic disks at bottom hole conditions. Compatibility tests between formate brine and cleaning fluids were performed at 300°F and 500 psi using HPHT visual cells (see-through cells).
Circulation of solids-free formate brine did not remove the external filter cake. Citric acid at 10 wt%, formic acid, and lactic acid were found to be incompatible with formate brine at room temperature. However, these acids were compatible with formate brine at temperatures greater than 122°F. Mixing of these acids with the formate in the field may cause operational problems. Only acetic acid and enzymes were compatible with formate brine. A formula was developed that is compatible at room and reservoir temperature. This formula was effective in removing filter cake. A corrosion inhibitor was added to protect downhole tubulars. This paper will discuss the development of this formula and all tests that led to its development.
A Faster Cleanup, Produced-Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studies
Authors: Bulat Daren , Chen Yiyan , Graham Matthew K. , Marcinew Richard , Adeogun Goke , Sheng Jack , Abad Carlos 
Published: February 2008

AbstractNatural gas reservoir development continues at a record pace in North America. Additionally, reservoir pressure depletion and declining quality of reserves have resulted in escalating drilling, completion, and workover costs per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions, the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity, and fluid recycling/handling are but a few strategies employed. Additionally, operating companies have been seeking other cost-control measures, including reducing the number of additives in fracture fluids and minimizing disposal costs of produced waters by recycling and by using them as the base for completion and fracturing fluids. Because of the uncertainty of the produced water impurity, composition, and concentration, it is extremely challenging to make a fracturing fluid compatible with produced water. Together with the need to gel produced water, the demand for more conductive fractures, along with the capacity to create sufficient fracture geometry, has led to the development of a unique surfactant-based system relatively insensitive to most produced waters, and even to some high-density brines. Fluid chemistry modifications employed to enhance performance allowed for reductions in mix-water and fluid-handling costs, shortened flowback/cleanup time, and provided equal or improved post-fracture production response. This paper focuses on a description of the fluid chemistry and performance along with numerous fracture treatment applications with a variety of mix-waters.