Offshore reservoirs requiring sand control pose a major completion challenge because of extremely high cost and risk involved in remedial treatments, particularly in sub-sea completion and/or deep-water environments. It is therefore of utmost importance to ensure sand control without sacrificing flow conformance, recoverable reserves and well deliverability throughout the expected life of the completion. A major trend in these environments is towards open-hole, horizontal, gravel-packed completions. Although gravel packing stabilizes the wellbore, it can also entrap the filter-cake formed by the reservoir drilling fluid, potentially resulting in high drawdown requirements (flow initiation pressures) and/or low production rates (retained permeabilities). The cleanup procedures in the industry have varied significantly from no cleanup at all to complicated two-stage breaker treatments involving post-completion coiled tubing intervention, with no guidelines existing in the literature. In this paper, we present experimental results and field cases involving filter-cake flow-back through gravel packs with and without cleanup. Effects of various parameters, including gravel size (40/60, 20/40, and 12/20), formation permeability, drill-solids type (clays, quartz) and concentration, and the type of cleanup fluid have been investigated. Flow initiation pressure and retained permeabilities during flow back are reported as a function of these parameters. The experimental results show that the flow initiation pressure is a strong function of gravel size and the type of drill solids. It is concluded that, in clean (low-to-no clay content) formations of large grains and high permeabilities (~ several darcies) requiring large gravel sizes (e.g., 12/20), an enzyme or an oxidizer treatment is sufficient based on laboratory results and productivity predictions. This conclusion is also supported by several field applications as shown. In lower permeability (~ 100–250 md) formations of small sand sizes requiring smaller gravel (e.g., 40/60) elimination of both the fluid loss control agent (starch) and bridging agent (CaCO3) is necessary based on high flow initiation pressures and low retained permeabilities. In intermediate permeability (~ 500–800 md) formations of medium size sand-grains typically requiring 20/40 gravel, the results depend strongly on the type of drill solids: in clean formations (no clays in drilling fluid), an enzyme or an oxidizer treatment is sufficient, while in dirty formations removal of both CaCO3 and starch is necessary. These results are also supported by field case histories presented in the paper. Introduction Gravel packing has been gaining wider popularity in open-hole horizontal completions where sand control is required, particularly in sub-sea completion and/or deep-water environment. The cost of intervention in such cases makes risk mitigation a much more pronounced task. Until recently, a large majority of horizontal sand control completions have utilized standalone screens. However, because a substantial fraction of these wells have failed prematurely (either productivity loss due to screen plugging or loss of sand control due to screen erosion),1 many operators have changed their primary completion technique in these wells from standalone screens to gravel packing. This is particularly true in formations containing a large fraction of non-pay (shale, mudstone/siltstone) and/or have a wide particle size distribution.2

Gravel-packing of open-hole highly-deviated or horizontal wells is increasingly becoming a common practice, especially in deep water and sub-sea completion environments where production rates may reach up to 50,000 BOPD or 250 MMSCFD. In these wells, reliability of the sand face completion, in addition to other factors, is of utmost importance due to the prohibitively high cost of intervention or side-tracking and the very high hydrocarbon recoveries required per well. To date the norm in gravel-packing such wells is water-packing or shunt-packing with water-based fluids. With both techniques, filter-cake removal treatments are conventionally done through coiled tubing after gravel packing, pulling out of the hole with the service tool and running in with the production/injection tubing. Furthermore, because conventional gravel-pack carrier fluids are water-based (brine or viscous fluids), water-based drilling fluids are traditionally used to drill the reservoir section to ensure compatibility and improve wellbore cleanup, even if the upper hole is drilled with a synthetic/oil-based drilling fluid. In this paper, we discuss several novel techniques that can substantially improve return on investment in gravel packing of open-hole horizontal completions, through reduced cost and process time, improved fluid management practices, increased productivity and/or reduced risk of future interventions, so mitigating against the risk of sand face completion failure or under-performance. The proposed techniques include:Simultaneous gravel-packing and filter-cake removal with water-based carrier fluids when the reservoir is drilled with a water-based drilling fluid: laboratory data relevant to gravel-packing are given and field case histories are discussed in detail.Simultaneous gravel-packing and cake cleanup with either water or a synthetic/oil-based carrier fluid when the reservoir is drilled with a synthetic/oil-based drilling fluid: laboratory data on cake removal while gravel packing are presented for both water-based and oil-based carrier fluids along with data on kinetics of cake removal.a new service tool that utilizes wash-pipe as continuous tubing and thus allows spotting of breaker treatments immediately after gravel packing: detailed description of the tool and its operation is given.Gravel-packing of highly-deviated or horizontal wells above fracturing pressure. Benefits offered by each of the proposed techniques are discussed in detail along with their current limitations. Introduction A great majority of the highly-deviated and horizontal wells are being completed as open holes, primarily because of their much higher damage tolerance, higher well productivities at high mobilities (kh/µ) and lower cost compared to cased holes. Although most of these wells in areas requiring sand control have been completed with standalone screens, a rapidly increasing fraction of them are now being gravel packed, particularly in deep water, high production rate and/or sub-sea completion environments (currently ca. 40%, and projected to be ca. 60% by 2003/2004). The major drivers for this current trend are the prohibitively high cost of intervention and much higher reliability associated with gravel packs.1,2

Fluid and mechanical friction (drag) place restrictive limits on many oilfield operations in which either fluid is pumped through pipe or pipe is moved within pipe. Since nearly all oilfield operations require at least one of these dynamics, friction loss due to fluid or mechanical movement is an important consideration. One example operation that involves both frictional forces is provided by coil tubing workovers in which wellbore solids are circulated to the surface using clear brine or viscosified fluids flowing at high rates, typically in turbulence. Energy losses to the walls of the tubing by the flowing fluid and frictional drag between the coil and the casing can prevent a fully successful operation due to excessive pump pressure, limited flow rate, and excessive stress on equipment or failure to reach desired depth. Metal-to-metal lubricants and fluid drag reducers are often used in these and similar operations to reduce the amount of energy lost to friction. During well completions or workovers when tools, pipe and fluids are inside casing or tubing, the frictional forces can be quite different than in the drilling operation where the interfaces are between drillpipe, drilling mud (and filter cake) and formation. Unfortunately, most of the lubricants in use today, outside of the drag reducers developed for production flow lines, were originally developed for drilling. As a consequence, their physical and chemical properties are not always optimized for the different performance criteria required in completions and workovers. This paper presents a new lubricant that meets many of the challenges presented to the working fluid during complicated completions and workovers. One unique property of the new lubricant is its complete solubility in most completion brines, including the high-density calcium bromides. Unlike many oilfield lubricants that are typically only dispersible in completion brine and in many cases grease, "cheese" or gunk in brine with high hardness (calcium and magnesium), this new lubricant does not increase the turbidity of the working fluid and remains soluble after exposure to high shear and temperature common during circulation. A beneficial outcome of this property is that the lubricant does not add to the oil and grease content of the completion or workover brine, nor does the additive sheen. These properties mean that the lubricant does not negatively impact the ability of the working fluid to be discharged overboard in areas such as the Gulf of Mexico. Its chemistry and solubility further means that in the case of losses to the producing formation, productivity is left undamaged as a result of wettability changes, emulsion formation, precipitation or other incompatibility. Laboratory data provided in this paper demonstrate its solubility and reduction coefficient of friction (CoF) in fresh water, seawater and high salinity and high density brine. Formation damage studies are presented and case histories are discussed in which low concentrations of the lubricant were used to offset frictional forces in the field, both mechanical and fluid related. Introduction Completion operations can minimize torque and drag through properly designed completion brine. Traditionally, attempts have been made to utilize conventional drilling fluid or brine-dispersible lubricants in completion fluids. The success of these types of lubricants has been very limited due to incompatibilities with the brines, especially those containing high concentrations of calcium and magnesium. The lighter completion fluids such as seawater, potassium chloride, sodium chloride and diluted calcium chloride are less lubricious than their higher density counterparts, thus, they often require friction reducing agents to provide lubricity. These types of brines are also generally discharged if prevailing environmental requirements allow. Cheesing (so called because the resulting emulsion resembles loose cheese), greasing and/or gunking of the lubricant can render it not only ineffective, but environmental restrictions later may disallow discharge of the treated brine. Furthermore, insoluble or dispersible additives that grease out in surface tanks and lines will cause troublesome surface cleaning that adds time and cost to the operation. Moreover, these types of additives generally result in damage to the formation. Thus, the need for a soluble, non-greasing, non-oily lubricant is evident.

Open-hole horizontal wells are increasingly used to improve reservoir exploitation and production rates by targeting specific zones and maximizing reservoir exposure. The drilling fluid of choice in many of these wells is "oil based" due to enhanced drilling rates with minimized friction as well as improved wellbore stability. However, in horizontal wells requiring gravel packs, the industry in general has been reluctant to use OB reservoir drilling fluids (RDF) for various reasons. Because the gravel pack (GP) carrier fluids that have been successfully used to date are all water-based and the use of OB-RDF would necessitate displacement of open hole to WB fluids prior to GP, the practice has been to switch to WB-RDF once in the reservoir section. This was due to concerns as to adverse fluid-fluid interactions resulting in sludging and difficulty in maintaining filtercake integrity while displacing OB-RDF in the open hole, leading to complex fluid management issues. An additional factor has been the perception that WB-RDF filtercakes are easier to remove should it be necessary, since most commonly used cleanup chemicals are water-based and the weighting/bridging agents used in the RDF are also water-wet if the RDF is water-based. In this paper, we present results from experiments conducted with OB-RDFs in the presence of gravel packs. We investigate two scenarios:the gravel pack carrier fluid is water-based, andthe gravel-pack carrier fluid is oil-based. In the first case, provided that no sludges are formed during displacement to water-based fluids, the retained permeabilities are comparable to or better than those obtained with WB-RDFs, although values lower than 0.04% can be expected in the presence of sludging. Another issue relevant to gravel packing wells drilled with OB-RDFs is the yield strength of their filtercakes in comparison to WB-RDFs. It is found through yield stress measurements of various RDF cakes that OB-RDFs have several orders of magnitude lower yield strength than their WB counterparts. This finding is consistent with the reported lower flow initiation pressures for OB-RDFs, and indicates that cake erosion during gravel packing is more likely with OB-RDFs. In order to optimize the sequence of fluids to obtain a good displacement of the RDF at field scale, we use a purpose-built numerical simulator. This simulator is a fluids mechanics code that can accurately calculate displacement fronts in field conditions: eccentric deviated annulus with as many fluids as necessary. Its main use is to detect unstable displacements such as channeling of the displacing fluid on the wide side of the annulus or slumping in horizontal portions. Furthermore, we provide data on a new oil-based gravel pack carrier fluid that can be used to eliminate fluid incompatibility and fluid management issues associated with the switch from OB to WB fluids. The laboratory and large-scale yard test results are presented, addressing critical considerations for oil-based GP carrier fluids. It is found that such emulsion systems can thicken or break (depending on the emulsifier concentration) at high shear rates unless the emulsion is made at the highest shear that it will be exposed to. The implications of these results on field practices are discussed along with recommendations on avoiding damage in gravel packed wells drilled with oil-based RDFs.

A new technical standard has been developed for assessing the performance and physical characteristics of heavy brines used in completion, packer, and drill-in operations. This technical standard includes procedures for evaluating the density, specific gravity, clarity, amount of suspended particulate matter, crystallization point, pH, and iron contamination. It also contains a discussion of gas hydrate formation and mitigation, brine viscosity, brine crystallization at high pressures, corrosion testing, buffering capacity, and a standardized reporting form. Introduction The American Petroleum Institute (API) has developed recommended practices (RP) for testing heavy brines. These recommended practices have been generated and documented by brine experts from industry under the auspices of API Committee 3, Subcommittee 13, Task Group 6. The first recommended practice for clear completion brines was published June 1, 1986 as "API Recommended Practice 13J Recommended Practice for Testing Heavy Brines" (RP-13J) [1]. This document contained three sections: Brine Density, Brine Crystallization Temperature, and Brine Clarity. Each section of the document was enhanced in the Second Edition[2] published March 1996. The Third Edition[3] was published December 2003 and greatly expanded the scope of RP-13J. In addition to substantially upgrading the existing sections of the document, the Third Edition added four new sections and six annex sections. The new additions to RP-13J are titled:Section 9Solids evaluation by gravimetric procedures,Section 10pH,Section 11Iron contamination,Section 12Daily completion fluid report,Annex ACompletions Fluid Report Form,Annex BGas Hydrates,Annex CBuffering capacity of brines,Annex DPressure crystallization of brines,Annex EBrine viscosity, andAnnex FPrinciple of corrosion testing. As we entered into the 21st Century, it became abundantly clear that recommended practices and standards needed to be globalized. Consequently, the API and authors of the Third Edition of RP-13J transformed that edition into the format required by the International Organization for Standardization (ISO). The resulting document, " Petroleum and natural gas industries- Completion fluids and materials- Part 3: Testing of heavy brines" [4] was generated and given the designation "ISO 13503–3: Testing of heavy brines" or more commonly ISO 13503–3. As of this writing, the document was being circulated in Final Draft for vote that will conclude in November 2005. This document and its counterpart API RP-13J (3rd Edition) are "living documents" that undergo continual enhancement. By convening appropriate work groups, Task Group 6 will continue to expand and update the documents, and provide procedures and standards for new sections such as buffering capacity and pressure crystallization. The purpose of this paper is to communicate information about the document "ISO 13503–3: Testing of heavy brines" to the oilfield industry, particularly to those engineers involved with the use and maintenance of clear completion brines.