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

The wettability of rocks is of fundamental importance to the understanding of fluid transport within hydrocarbon reservoirs. Wettability is intimately tied to the zeta potential, which is determined by the electrostatic forces among the rock's mineral constituents. Extensive prior research has been conducted into the relationship between wettability and surface forces of shale samples that have been ground up and/or otherwise been altered. However, very little attention has been given to measuring the zeta potential of the surface of unbroken, intact shale samples. A new technique is explored in this paper that investigates the zeta potential of the actual surface of shale samples in one intact piece. The surface zeta potential of shales was found to be strongly determined by the mineral composition and the cation exchange capacity (CEC) of the shale. Shales containing higher amounts of silicates (e.g. quartz, feldspar, and clays such as Illite and Smectite) tended to be water-wet and exhibit higher negative zeta potential values. Shales that contained higher amounts of carbonates (dolomite, aragonite, calcite, etc.) were more oil-wet with zeta potential values that were less negative or slightly positive. Measurements were also performed on Berea and Boise sandstone in order to compare organic vs. inorganic samples. Results for common shales showed Mancos and Marcellus to be intermediate-wet, Oxford and Eagleford to be moderately oil-wet, and Arne to be highly water-wet. Additionally, the zeta potential was also studied in various ionic and nano-particle solutions.

Summary The operational use of nanoparticles (NPs) in drilling and completion fluids is still limited at the present time, in part because of a lack of consistent evidence for and clarification of NP interactions with rock formations, formation fluid, and other fluid additives. For instance, previous fluids research emphasized that NPs bring about pore plugging, which reduces pressure transmission and, in turn, fluid inflow, into the shale pore matrix, which ultimately helps stabilize the borehole. However, it is difficult to understand how pore plugging might be accomplished in the absence of any substantial filtration in shales, considering that the minimal permeability of shales does not allow for any appreciable Darcy flow. This paper addresses the crucial question: “How, when, and why do NPs plug shale pore throats?” Zeta-potential (ZP) measurements were carried out on aqueous NP dispersions and on intact thin shale sections exposed to nanofluids to determine the degree of interaction behavior between NPs and shale. The experimental data were then used to calculate Derjaguin-Landau-Verwey-Overbeek (DLVO) curves (describing the force between charged surfaces interacting through a liquid medium) to determine if the total potential energy was sufficient for NPs to diffuse through the repellent barrier and attach to the shale surface. Calculated DLVO curves were used to demonstrate the NPs ability to contribute to borehole stability, but did not directly correlate the effects the NPs had on shale stability. Experiments, including pore pressure-transmission tests (PTTs), which measure fluid pressure penetration in shale, and modified thick-walled-cylinder (TWC) collapse tests, which explore the influence of NPs on the collapse pressure of shale samples, were conducted to directly investigate the effects of NPs on borehole stability in shale. Our investigation showed that NPs can reduce fluid pressure penetration and delay borehole collapse in shale, but only under certain conditions. Electrostatic/electrodynamic interaction between NPs and shale surfaces, governed by DLVO forces, is the main mechanism that leads to pore-throat plugging, reducing pressure transmission, which in turn benefits borehole stability by slowing down near-wellbore pore-pressure elevation and effective-stress reduction. For Mancos Shale, 20-nm anionic nanosilica particles were effective in partially plugging the pore-throat system, depending on the pH of the nanofluid, which affects the surface potential and ZP of both NPs and shale. Furthermore, cationic nanosilica showed better results for pore-plugging capabilities than the anionic nanosilica. Our findings lead to interesting challenges for the practical field application of NP-based drilling fluids for borehole stability, given that efficacy depends on the specific type of shale; the specific type, size, and concentration of NP; the interaction between NPs and shale; and external factors, such as pH, salinity, and temperature. Therefore, NP use for practical shale stabilization requires a dedicated, thoroughly engineered solution for each particular field application, and is unlikely to be “one size fits all.”

The operational use of nanoparticles (NPs) in drilling and completion fluids is still limited at the present time, in part due to lack of consistent evidence for - and clarification of - NP interactions with rock formations, formation fluid, and other fluid additives. For instance, previous fluids research has emphasized that NPs bring about "pore plugging" that reduces pressure transmission, and in turn fluid inflow, into the shale pore matrix which ultimately helps stabilize the borehole. However, it is difficult to understand how pore plugging might be accomplished in the absence of any considerable filtration in shales considering the very low permeability of shales does not allow for any appreciable Darcy flow. This paper addresses the crucial question: "how, when, why do nanoparticles plug up shale pore throats?" Zeta Potential (ZP) measurements were carried out on the aqueous dispersions (NPs) and on intact shale thin sections exposed to the nanofluid in order to determine the degree of interaction behavior between NPs and shales. The experimental data was then used to calculate DLVO curves (describes the force between charged surfaces interacting through a liquid medium) in order to determine if the total potential energy was sufficient for NP's to diffuse through the repulsive barrier and attract (or overcome repulsion) to the shale surface. Estimated DLVO curves are used to demonstrate the NP's ability to contribute to borehole stability but are not directly correlated, and therefore, NP effects on shale stability were studied in detail using pore pressure transmission tests (PTT), which measure fluid pressure penetration in shales, and modified Thick Wall Collapse (TWC) tests, which explore the influence of NPs on the collapse pressure of shale samples. Our investigation shows that NPs can reduce fluid pressure penetration and delay borehole collapse in shales, but only under certain conditions. Electrostatic and electrodynamic interaction between NP's and shale surfaces, governed by DLVO forces, is the main mechanism that will lead to pore throat plugging, reducing pressure transmission, which in turn benefits borehole stability by slowing down near-wellbore pore-pressure elevation and effective stress reduction. For Mancos shale, it was shown that 20 nm nanosilica (anionic) are effective in partially plugging the pore throat system, depending on the pH of the nanofluid, which affects the surface potential and ZP of both NPs and shale. Furthermore, the positively charged nanosilica (cationic) showed better results for pore-plugging capabilities than the anionic nanosilica. The findings lead to some interesting challenges for the practical field application of NP-based drilling fluids for borehole stability, given that efficacy will depend on the specific type of shale, the specific type, size and concentration of NP, the interaction between NP-shale, and external factors such as pH, salinity, temperature etc. NP use for practical shale stabilization therefore requires a dedicated, thoroughly engineered solution for each particular field application, and is unlikely to be "one size fits all".

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn this paper, we present a novel approach for drilling and completing open hole horizontal wells with a fully compatible synthetic/oil-based fluid system utilizing shunt tube technology. The proposed RDF is a synthetic/oil-external emulsion that is reversible through exposure to a fluid of pH less than 7. A surfactant package included in the RDF waterwets the bridging/weighting agents (e.g., CaCO 3 ) upon reversal of the emulsion. The synthetic/oil external emulsion developed for gravel packing typically contains 50-75% by volume aqueous phase as the internal phase and is completely solids-free. The internal phase can either be brine or a pHreducer as well as a fit for purpose dissolver for the bridging agents. The pH-reducing property of the internal phase provides the required break mechanism for the S/OB-RDF emulsion remaining in the RDF filtercake under leakoff conditions allowing the bridging agents and drill solids to be water-wet, ensuring dissolution of the bridging agents.Laboratory data are provided for filtercake removal kinetics as a function of temperature, overbalance during gravel packing, gravel mesh size, and drill solids concentration in the RDF. Rheological data are given. Retained permeabilities and flow initiation pressures measured with the combined core and gravel-pack system are presented. Implications of the laboratory results on field practice are discussed.