|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Accelerators speed up or shorten the reaction time required for a cement slurry to become a hardened mass. In the case of oilfield cement slurries, this indicates a reduction in thickening time and/or an increase in the rate of compressive-strength development of the slurry. Acceleration is particularly beneficial in cases where a low-density (e.g., high-water-content) cement slurry is required or where low-temperature formations are encountered. Of the chloride salts, CaCl2 is the most widely used, and in most applications, it is also the most economical. The exception is when water-soluble polymers such as fluid-loss-control agents are used.
Abstract Advancement in High Performance Water Based Mud (HPWBM) coupled with a deeper understanding of shale and chemical interaction has taken a leap in recent years enabling the drilling of challenging wells whilst replacing Synthetic Based Mud (SBM) as the preferred technical option. The exceptional inhibition properties, versatility to chemical manipulation and stability, as well as being an environmentally beneficial alternative to SBM, HPWBM has proven to be a robust solution for drilling the challenging Muderong shale and highly depleted reservoir sands in the field. Through a detailed field wide offset review focusing on wellbore stability and shale reactivity relationship observations, time dependent shale reactivity and an engineered bridging package was the basis of a successful fluid formulation and selection which then resulted in a flawless execution of the challenging well. Various testing of shale cuttings from the field paired with an offset review was key to understanding the extent of shale reactivity in relation to the type of shale being drilled and cause of shale instability in the area. These results were imperative in providing technical justification to utilise HPWBM for drilling through the Muderong shale. Applying detailed reservoir drilling fluid analysis to the overburden drilling fluids design and incorporating previous offset fluid design learnings, provided a robust and versatile drilling fluid system. This paper will review the steps undertaken to validate the selection of HPWBM over SBM through detailed analysis of wellbore stability, shale reactivity, permeability assessment, pore throat sizing and pore pressure transmission. It will present the misnomer of comingling the wellbore stability requirement, primarily mud weight, with shale reactivity in the field as well as the relation between the plateauing of shale reactivity curves to near well wellbore swelling. Extensive laboratory testing was performed to formulate and demonstrate the efficacy of the bridging package in addressing differential sticking, losses and wellbore strengthening in highly depleted sands. In addition, this paper will also present actual field results on stability of the fluid properties along with resultant torque and drag throughout drilling of a directional well with no requirement for lubricants. This paper should be of interest to all engineers and technologists who are involved in shale reactivity analysis, well design, drilling fluids design, selection and interaction as well as highly depleted reservoir sand drilling.
Chuprin, Maksym (University of Louisiana at Lafayette) | Chavez, Nelson (University of Louisiana at Lafayette) | Nath, Fatick (University of Louisiana at Lafayette) | Mokhtari, Mehdi (University of Louisiana at Lafayette)
Tuscaloosa Marine Shale (TMS) is an emerging liquid-rich shale play with high clay content on an average of 50 wt. % in the eastern part of Louisiana and Southern Mississippi. The high clay content of TMS leads to drilling, wellbore instability, and fracturing performance issues, which is costly. Therefore, it is imperative to design water-based drilling and fracturing fluids with an effective shale inhibitor to mitigate swelling and maintain clay flocculation state to sustain wellbore structural integrity. The objective of this study is the screening of the clay stabilizers such as KCl, and NaCl inorganic brines and providing the baseline for the Tuscaloosa Marine shale treatment utilizing well-established methodologies such as capillary suction time (CST) and roller oven (RO) tests. The results of the experimental investigation on two TMS wells suggested that the application of KCl in the concentration of 6% and 4% provides more excellent stabilization to Tuscaloosa Marine shale, outperforming the best results of NaCl by 38%. It was found that the increase of the ionic strength of KCl brine from 4% to 6%, does not correspond to better stabilization of all TMS specimens. In some cases, when the total clay in TMS exceeds 50%, the low grade of NaCl brine follows the freshwater pattern providing almost no contribution to the shale inhibition.
This work discusses the merits of KCl application to stabilization of high clay Tuscaloosa Marine shale in terms of data analysis and attributes such as ionic size, hydration energy, and osmotic forces. There is no consensus regarding appropriate clay inhibitor on the stability of highly clay-rich and water-sensitive formation like TMS. This study provides an innovative insight into selecting the efficient stabilizer for this clay-rich formation, which is essential to minimize the formation damage and improve recovery mechanisms.
Shale with high clay concentration has been known for posing difficulties to the Oil and Gas industry in economically producing hydrocarbons from abundant unconventional resources. Nowadays, more than 70% of the drilled formations are shales that accounted for more than 89% of wellbore instability problems (Steiger et al. 1992). The issues of this might be rooted in the structural and chemical makeup of the shale. From the total amount of the hydrocarbon-rich formations, approximately 95% of them contain various clay minerals in the composition (Berry et al. 2008). The most abundant clay groups that have been found in the shale formations are smectite, illite, kaolinite, and chlorite groups (Almubarak et al. 2015). Among these clays, the swelling aluminosilicate mineral is considered to be smectite due to the T-O-T chemical structure that leads to a dramatic colloidal expansion by absorbing water molecules. However, differentiation of clays on swelling and non-swelling groups may not be feasible to a certain extent since each of them has free energy, which in contact with water is released, ensuing conversion into the swelling index (Hayatdavoudi 1999). Once the shale is exposed to a water-based fluid, the thermodynamic equilibrium that has been established between the formation and pore fluid is modified, which impacts clay minerals by changed activity inducing the cations exchange (Abdullatif et al. 2020). According to that, the most effective treatment design should consider all clay minerals presented in the tested specimen and their precise concentration.
Kamispayev, Akylbek (Tengizchevroil LLP) | Gazizova, Elima (Tengizchevroil LLP) | Skopich, Anton (Tengizchevroil LLP) | Munbayev, Timur (Tengizchevroil LLP) | Neubauer, Edward (Tengizchevroil LLP) | Clarke, John (Tengizchevroil LLP)
The PDF file of this paper is in Russian.
The deposition of scale in the near-well formation and production string can result in a significant decrease in well productivity. Properly designed scale inhibitor squeezes can successfully prevent scale deposition and extend well performance. Even though most wells in the Tengiz field produce virtually water free oil (less than 1% watercut (WC)), inorganic scales have been observed in many of these wells. Frequent acid stimulations are required to maintain the optimum well performance.
An extensive research project was initiated to reduce the need for frequent acid treatments and still maintain well deliverability at sustained rates. To identify an effective scale inhibitor product, inhibitor-brine compatibility testing and dynamic tube-blocking performance testing were conducted. Field application of the selected inhibitor in both low and high rate wells has verified the effectiveness of the squeezes. Treatment with the scale inhibitor attained sustainable well productivity and delayed the need for subsequent acid stimulation treatments.
This paper will share the best practices in scale inhibitor design, inhibitor selection, identification of well candidates, the execution and post treatment surveillance stages. Case studies shown to illustrate the performance of scale inhibitor squeezes in Tengiz.
Abstract Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery. Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage. The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.
Abstract Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity. In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated. The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
Abstract An unconventional clay-control substitute was introduced in the Middle East and North Africa (MENA) region, where a total of twenty-nine wells have been completed successfully. This paper presents a homogenous, on-the-fly clay stabilizer, which renders clay insensitive to fresh water, preventing swelling and migration while leaving formation/fluid properties unchanged. Formation damage and drilling difficulties are very commonly associated with clay problems. Clay-control additives are crucial in any drilling operation, particularly in Saudi Arabian gas wells where drilling activities use underbalanced coiled tubing drilling (UBCTD). UBCTD optimizes this on-the-fly alternative and achieves multiple objectives. The primary objective of UBCTD is to minimize fresh water contact time with the formation through flowing back; however, having to change the bottom hole assembly (BHA) because of wear halts circulation and production and increases fresh water contact with the formation, which could lead to clay swelling in the near wellbore area and result in damage. This new fluid system has proven to provide superior protection even at higher rates of penetration. In addition, inorganic compound quality and inconsistency could lead to deposits on equipment and affect instrumentation performance with UBCTD at the production/treatment systems when flowing back while drilling. These issues can be avoided with this treatment, and the costs associated with equipment rental can be reduced. Additionally, concentrations can be changed on-the-fly as needed depending on the formation. This clay stabilization fluid helps control clay swelling, fines migration, and decreases hydrostatic pressure and friction pressure when exposed to a freshwater-based fluid system. It fundamentally adheres to the clay mineral surface and prevents ion exchange, therefore providing pore throat protection and deterring damage to the formation matrix. The treatment was used during underbalanced drilling projects where each well/project had two to three laterals of low permeability. It was successfully used in nine pilot projects with excellent results, awarding distinctive advantages compared to typically used inorganic-based clay and shale stabilizers This development could increase the efficiency of downhole motors and drill bits as a result of low friction pressure and minimal deposits left behind. No additional equipment or manpower is necessary compared to other inorganic compound treatments. In addition, it reduces mixing time (on-the-fly) and is added at a lower concentration, which helps reduce logistical challenges and makes the treatment more efficient at a lower cost and with a reduced footprint. Original permeability is not affected by the addition of this fluid system, and permanent clay stabilization is provided. Data are presented and cross-checked with adjacent wells/candidates that used conventional clay protection such as inorganic compounds. Gamma-ray logs, the rate of penetration (ROP), productivity index (PI), and associated depth are also presented. Wells drilled with this fluid exhibited excellent protection throughout laterals and open-hole sections.
Lafitte, Valerie (Schlumberger) | Panga, Mohan Kanaka (Schlumberger) | Vaidya, Nirupama (Schlumberger) | Nikolaev, Max (Schlumberger) | Enkababian, Philippe (Schlumberger) | Teng, Ling Kong (Schlumberger) | Zhao, Haiyan (Schlumberger)
Abstract Water production is a major concern for oil companies because it involves not only a high cost for handling the water on surface, but also issues related to scale and corrosion in tubulars, and an overall decrease of hydrocarbon production. Finding the right solutions for each case is a challenge because there is no one solution that fits all. Chemical treatments for water shutoff are cheaper than mechanical treatments and can offer more targeted and customized design, but they often come with higher operational risks. A new water control system based on a single particulate additive was extensively evaluated under laboratory conditions and then successfully implemented in the field. The fluid is easy to prepare using traditional field mixers and does not need curing after it is pumped into the formation, thus saving time and cost compared to most conventional water shutoff systems. The fluid was evaluated in the laboratory with a wide range of formation permeabilities and injection conditions using the fluid loss apparatus, permeameter, and formation response tester. The viscosity and stability of the fluid in different water salinity and concentrations were also investigated. Overall, it was found that the new fluid system was very efficient in shutting-off formations greater than 50 md up to a few darcies. Those results were consistent with the nature of the plugging mechanism, which relies on physical pore plugging alone. The system could be further tuned depending on the formation permeability. In the presence of oil saturation, the penetration of the particulate system was found limited as compared to a single-phase, water-saturated core.
Summary The investigation of nanotechnology applications in the oil and gas industry is increasing gradually; therefore, this technology needs more exploration to unveil promising applications. In this study, an experimental investigation of nanotechnology on the apparent viscosity, viscoelastic properties, and filtration performance of surfactant-based fluids (SBFs) or viscoelastic surfactants (VESs), polymeric fluids, and SBF/polymeric-fluid blends is presented. The concentration of SBF is 5 vol%, whereas that of polymeric fluids is 33 lbm/1,000 gal guar. Besides, both fluids contained 4 wt% potassium chloride (KCl). In addition, Blend-A and Blend-B were prepared by mixing SBF and polymeric fluids in the ratio of 75/25 and 25/75 vol%, respectively. Nanofluids were prepared by adding 20-nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4 wt%, to the clean fluids. Apparent viscosity and viscoelastic data were gathered with a rheometer within a temperature range of 75 to 175°F, whereas filtration tests were conducted with a wall-mount filter press at ambient temperature and 100-psi differential pressure. The results indicate an enhancement in the apparent viscosity and viscoelastic properties of surfactant-based and polymeric nanofluids up to a nanoparticle concentration of 0.24 and 0.4 wt%, respectively. Blend-A nanofluids show improvement in apparent viscosity and viscoelastic properties at a nanoparticle concentration of 0.058%. Similarly, Blend-B displayed favorable results up to a nanoparticle concentration of 0.24 wt% at temperatures of 125 to 175°F. Promising filtration results were displayed with surfactant-based nanofluids and Blend-A nanofluids at all nanoparticle concentrations, but the performance at 0.24 and 0.4 wt%, respectively, is slightly better. Polymeric nanofluids and Blend-B nanofluids revealed very good filtration results at all nanoparticle concentrations, but the performance at 0.24 and 0.058 wt%, respectively, is slightly better with a percentage reduction in API filtrate volume of 70.2 and 69.8%, respectively. A trial run was made with a commercially available fluid-loss additive [polyanionic cellulose (PAC)] in polymeric fluids at the same nanoparticle concentrations; the result confirmed that nanosilica facilitates the achievement of a superior filtration property. Comparison of apparent viscosity, viscoelastic properties, filtration performance, and economic analysis revealed Blend-A nanofluid as the preferred choice. Further, Blend-A nanofluid (at 0.058 wt%) is selected as the best on the basis of filtration performance. The selected fluid was optimized at lower nanoparticle concentrations (0.02, 0.01, and 0.002 wt%). Interestingly, using Blend-A nanofluid at 0.002 wt%, compared with the initial recommendation of 0.058 wt%, which costs USD 171.7/bbl, reduces the cost of nanoparticles required for preparing 1 bbl of this fluid to USD 5.8. Therefore, from a filtration-performance standpoint, Blend-A nanofluid is recommended for use at a nanoparticle concentration of 0.002 wt%. The application of nanotechnology on the apparent viscosity, viscoelastic behavior, and filtration properties of SBF, polymeric fluids, and SBF/polymeric-fluid blends can deliver some benefits, if nanoparticle concentrations are selected carefully. These nanofluids will be applicable for oilfield operations such as hydraulic fracturing.