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Abstract Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
Abstract In this paper, the authors examine the impacts of natural fractures on the distribution of slurry in a well with a permanent fiber installation and drill bit geomechanics data. Additionally, they propose a framework for further investigation of natural fractures on slurry distribution. As part of the Marcellus Shale Energy and Environmental Laboratory (MSEEL), the operator monitored the drilling of a horizontal Marcellus Formation well with drill bit geomechanics, and subsequent stimulation phase with a DAS/DTS permanent fiber installation. Prior to the completion, the authors used an analytical model to examine the theoretical distribution of slurry between perforation clusters from a geomechanics framework. A perforation placement scheme was then developed to minimize the stress difference between clusters and to segment stages by the intensity of natural fractures while conforming to standard operating procedures for the operator's other completions. The operator initially began completing the well with the geomechanics-informed perforation placement plan while monitoring the treatment distribution with DAS/DTS in real time. The operator observed several anomalous stages with treating pressures high enough to cause operational concerns. The operator, fiber provider, and drill bit geomechanics provider reviewed the anomalous stages’ treatment data, DAS/DTS data, and geomechanics data and developed a working hypothesis. They believed that perforation clusters placed in naturally fractured rock were preferentially taking the treatment slurry. This phenomenon appeared to cause other clusters within the stage to sand-off or become dormant prematurely, resulting in elevated friction pressure. This working hypothesis was used to predict upcoming stages within the well that would be difficult to treat. Another perforation placement plan was developed for the second half of the well to avoid perforating natural fractures as an attempt to mitigate operational issues due to natural fracture dominated distribution. Over the past several years, the industry's growing understanding of geomechanical and well construction variability has created new limited-entry design considerations to optimize completion economics and reduce the variability in cluster slurry volumes. Completion engineers working in naturally fractured fields, such as the Marcellus, should consider the impact the natural fractures have on slurry distribution when optimizing their limited-entry designs and stage plan.
John, Blevins (Hibernia Resources) | Van Domelen, Mark (Downhole Chemical Solutions) | West, Zach (Downhole Chemical Solutions) | Rall, Jason (Downhole Chemical Solutions) | Wakefield, Drake (Downhole Chemical Solutions)
Abstract Since the early development of unconventional resource plays, slickwater fracturing fluids have expanded rapidly and are now the most common type of fluid system used in the industry. Slickwater and viscosifying friction reducer (VFR) fluids consist of polyacrylamide (PAM) polymers and are typically delivered to location in a liquid form such as a suspension or emulsion in a hydrocarbon-based carrier fluid. Recently, advances in dry powder delivery operations have provided unique advantages over the liquid versions of FRs including cost savings and improved health, safety and environmental (HSE) aspects. This paper describes the dry powder delivery process and describes the advantages that this new technology has brought to field operations. The method involves delivering polyacrylamide powder for slickwater fracturing treatments directly into the source water on location, thereby eliminating the use of liquid polymer slurries or emulsions. Liquid friction reducers typically contain 20-30% active polymer loading, with the remaining volume being the carrier fluid to keep the polymer in suspension. By delivering 100% powder, several benefits are gained including elimination of truck deliveries of FR liquids to location, reduction of total chemical volumes by 70-80%, reduction of spill hazards, and lower overall chemical costs. Different powders are available for various applications including the use of fresh or produced water, and viscosifying or non-viscosifying polymers. The key technology for "dry on the fly" (DOTF) operations is the powder delivery equipment. Due to the different molecular structures between polyacrylamide and guar polymers, delivering PAM is more technically challenging than guar and requires much higher mixing energy to achieve proper dispersion and hydration. The delivery system described in this paper uses a unique technology which creates the necessary conditions for powder mixing and has been successfully applied on over 350 wells since early 2019, with over 7,000 tons of polymer delivered.
Summary To determine which salt-based cement system (potassium chloride or sodium chloride) was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. Four slurry designs (a lead and tail slurry used on each casing string) were programmed. Each slurry was designed and tested as two distinct systems using potassium chloride and sodium chloride salt, respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. (2002), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. On the basis of these results, conclusions were then made on which salt slurry system (potassium chloride or sodium chloride) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt-formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a potassium chloride salt-based slurry delivered improved liquid and set properties as compared with a sodium chloride salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only sodium chloride salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that potassium chloride salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m (328.1 ft) thick.
Adjei, Stephen (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals (Corresponding author) | Sarmah, Pranjal (email: email@example.com)) | Chinea, Gonzalo (Baker Hughes)
Summary Fly ash, which is a pozzolan generated as a byproduct from coal-powered plants, is the most used extender in the design of lightweight cement. However, the coal-powered plants are phasing out due to global-warming concerns. There is the need to investigate other materials as substitutes to fly ash. Bentonite is a natural pozzolanic material that is abundant in nature. This pozzolanic property is enhanced upon heat treatment; however, this material has never been explored in oil-well cementing in such form. This study compares the performance of 13-ppg heated (dehydroxylated) sodium bentonite and fly-ash cement systems. The raw (commercial) sodium bentonite was dehydroxylated at 1,526°F for 3 hours. Cement slurries were prepared at 13 ppg using the heated sodium bentonite as partial replacements of cement in concentrations of 10 to 50% by weight of blend. Various tests were done at a bottomhole static temperature of 120°F, bottomhole circulating temperature of 110°F, and pressure of 1,000 psi or atmospheric pressure. All the dehydroxylated sodium bentonite systems exhibited high stability, thickening times in the range of 3 to 5 hours, and a minimum 24-hour compressive strength of 600 psi. At a concentration of 40 and 50%, the 24-hour compressive strength was approximately 800 and 787 psi, respectively. This was higher than a 13-ppg fly-ash-based cement designed at 40% cement replacement (580 psi).
Eid, E. (University of Stavanger) | Tranggono, H. (University of Stavanger) | Khalifeh, M. (University of Stavanger (Corresponding author) | Salehi, S. (email: firstname.lastname@example.org)) | Saasen, A. (University of Oklahoma)
Summary Our objective is to present selected rheological and mechanical properties of rock-based geopolymers contaminated with different concentrations of drilling fluids. The possible flash setting and the maximum intake of drilling fluids before seeing a dramatic deterioration of the geopolymers are presented. Rock-based geopolymers designed for cementing conductor and surface casing were prepared and cured for up to 28 days at 22°C and atmospheric pressure. Water-based drilling fluids (WBDFs) and oil-based drilling fluids (OBDFs) were designed in accordance with the recommendations from the petroleum industry. The fluid samples were prepared, and their viscous behavior was characterized before and after hot-rolling. The geopolymeric slurries were mixed and then blended with the prepared drilling fluid volumes. The contaminated geopolymeric slurries were cured and tested at different time intervals. American Petroleum Institute (API) Class G neat cement was used as a reference. These samples were cured and contaminated with the same drilling fluids. The properties of contaminated geopolymer slurries were benchmarked with those of the contaminated Class G cement. The obtained mechanical properties showed that the rock-based geopolymers are more sensitive to WBDFs than to OBDFs. However, for contaminated Portland cement samples, the obtained results were opposite, and the contamination effect of OBDF on cement was more noticeable than WBDF. The impact of geopolymer contamination is a function of curing time. Although geopolymeric samples showed dramatic strength retrogression at the early time, strength buildup of the samples compensated for the impact of contamination.
Phyoe, Thein Zaw (Schlumberger) | Salazar, Jose (Schlumberger) | Albuja, Eduardo Herrera (Schlumberger) | Kapoor, Saurabh (Schlumberger) | Orfali, Mohd Waheed (Schlumberger) | Kondo, Kazuyoshi (Schlumberger) | Sajid, Muhammad (Schlumberger) | Rahhal, Gilbert (Schlumberger)
Abstract Lost circulation while drilling across vugular or naturally fractured formations is a difficult challenge which will come with high cost for the oil and gas industry. When lost circulation encounter, the drilling company will result in nonproductive time and remedial operational expenses. Most of the fields in UAE are encountering lost circulation problems while drilling across surface sections, which are difficult to control with conventional lost circulation solutions. Newly engineered high-performance lightweight thixotropic proves beneficial to control losses in vugular and natural fractured formations. The main challenge while drilling the surface section in one UAE field is the total loss of returns and flowing formation. This leads to the inability to continue drilling due logistics to continue producing drilling fluid and to keep the well under control and risk of stuck pipe due to poor cuttings removal. Conventional low-density cement slurries have been widely used to cure losses while drilling, but with low effectiveness. A new lost circulation solution that combines lightweight (10.5–lbm/galUS) high-performance cement and a thixotropic agent produce an engineered high-performance lightweight thixotropic lost circulation solution with fast gel strength and improved compressive strength, enabling the plugging of large voids and fractures to recovery wellbore integrity required to continue drilling. Extensive laboratory qualification tests were performed for static gel strength development to confirm the plugging efficiency and compressive strength development. The results were promising with more than 110 lbf/100 ft of static gel strength in 10 minutes and compressive strength development of 1,000 psi within 24 hours at low surface temperature. In addition, a transition time (TT) with on-off-on test demonstrated more faster gel strength development was developed when the reduction of the shear rate and regained pumpable with reapplication of shear. In one of the wells, total losses were encountered while drilling across surface section. The lightweight high-performance thixotropic solution was pumped for the first time worldwide, proved that the innovative lost circulation solution was effective in curing the losses, and enabled the operator to continue drilling the section to TD. This case study demonstrates that the engineered system is effective in curing losses and reducing nonproductive time. The unique properties of more faster gel strength and enhanced compressive strength make this system more effective for treating a different types of lost circulation scenarios during drilling (Jadhav and Patil, 2018). New high-performance lightweight thixotropic cement lost circulation solution exhibits strong performance in curing total losses and establishing well integrity with reliability.
Abd Rahman, Siti Humairah (PETRONAS Research Sdn. Bhd.) | Medvedev, Anatoly (Schlumberger) | Yakovlev, Andrey (Schlumberger) | Sazali, Yon Azwa (PETRONAS Research Sdn. Bhd.) | Jain, Bipin (Schlumberger) | Hassan, Norhasliza (PETRONAS Research Sdn. Bhd.) | Thompson, Cameron (Schlumberger)
Abstract With the development of new oil formations and with the advent of new directions in the global energy sector, new requirements for materials for well construction appear. With the close attention to environmental footprint and unique properties, one of the promising materials for well cementing is geopolymers. Being a relatively new material, they are characterized by low carbon footprint, high acid resistance and attractive mechanical properties. This article is aimed at developing new geopolymer slurries for the oil industry, their characterization and field implementation analysis. With the ultimate goal of developing a methodology for the analysis of raw materials and designing the geopolymer slurries, studies were carried out on various raw materials, including different types of fly ash. Based on the data obtained and rapid screening methods, an approach was developed to formulate a geopolymer composition recipe. Since not all cement additives directly work in geopolymers, special attention was paid to control the thickening time and fluid loss. The methods of XRD, XRF, ICP-MS, density, particle size distribution measurements as well as API methods of cement testing were used to understand the composition and structure of the materials obtained, their properties and design limitations. A special approach was applied to study the acid resistance of the materials obtained and to compare with conventional cements and slags. Using one of the most common sources of aluminosilicate, fly ash, formulations with a density of 13.5 – 16.5 lbm/galUS were tested. A sensitivity analysis showed that the type of activator and its composition play a critical role both in the mechanical properties of the final product and in the solidification time and rheological properties of the product. The use of several samples of fly ash, significantly different in composition, made it possible to formulate the basic rules for the design of geopolymers for the oil industry. An analysis was also carried out on 10 different agents for filtration and 7 moderators to find a working formulation for the temperature range up to 100°C. The samples were systematically examined for changes in composition, strength, and acid resistance was previously measured. Despite the emergence of examples of the use of geopolymers in the construction industry and examples of laboratory testing of geopolymers for the oil industry, to the best of our knowledge, there has been no evidence of pumping geopolymers into a well. Our work is an attempt to develop an adaptation of the construction industry knowledge to the unique high pressure, high temperature conditions of the oil and gas industry. The ambitions of this work go far beyond the laboratory tests and involve yard test experiments.
Abstract Sustained casing pressure (SCP) is a very costly event for any operator either at production phase or at the end of a well’s lifecycle. SCP is a result of incomplete hydraulic isolation across hydrocarbon bearing zone. In one of the gas fields in Malaysia, notoriously known for shallow gas hazard, drilled development wells which have reportedly been suffering SCP. In the past, various improvements in cement slurry design and placement methods were deployed in order to provide complete zonal isolation, especially at the shallow gas sand, yet SCP issue was encountered occasionally. In the current development campaign, different strategy to providing annulus sealing was adopted. This paper discusses proactive steps taken in the slurry design, fit together with the dual stage cementing approach, as a primary means of placing cement above the shallow hazard interval. During the design phase, essential key parameters that would lead to successful placement of cement in the annulus as well as unique slurry design that suits for two stage cementing methods were studied. Risk involved in first stage cementing is one of the most important steps that should be analyzed in detail and put mitigation measures in place to ensure the second stage cement job can be performed as planned. In addition to the slurry properties, such as fluid-loss value, gas-tightness, etc., thickening time and top of cement (TOC) of the lead slurry in the first stage cement job has become enormously critical in designing dual stage cementing job in order to assure cement ports in the stage collar are not covered with hard cement forcing the termination of second stage job prematurely. Besides cementing design, careful selection of the stage collar location and casing annulus packer in the string is also of significant importance in leading to successful two stage cement job. Two development wells with above approached has been delivered and no sustained casing pressure has been experienced. This proactive approach to use two stage cementing as primary plan has proven to successfully eliminate the risk of SCP, which was a frequent struggle in their sister wells drilled with primary cementing in the past in the same field. The risk analysis combined with careful considerations of critical cementing design parameters and selection of stage tool location have become a novel approach to combat against SCP in this gas field.
Li, Yi (China oilfield services limited) | Mohammad, Solim Ullah (China oilfield services limited) | Ai, Wu chang (China oilfield services limited) | Kumar, Avinash Kishore (PETRONAS Carigali Sdn Bhd) | Hen, Lau Chee (PETRONAS Carigali Sdn Bhd) | Hun, Ong Sheau (PETRONAS Carigali Sdn Bhd) | Qiu, Guo liang (China oilfield services limited) | Duan, Zhi wei (China oilfield services limited) | Mahaiyudin, Ahmad Rizal (China oilfield services limited) | Wang, Zhen (China oilfield services limited) | Luo, Yu wei (China oilfield services limited) | Xiang, Xian zhong (China oilfield services limited) | Yu, Bin (China oilfield services limited) | Chua, Keting (China oilfield services limited) | zhang, Hao (China oilfield services limited) | Ma, Chun Xu (China oilfield services limited) | Fang, Guo wei (China oilfield services limited)
Abstract In offshore Malaysia field, several development wells were drilled and cemented in 2019. The presence of shallow gas zone directly below the surface casing shoe posed a significant challenge to isolate shallow gas flow. A High presence of carbon dioxide (CO2) also increased the complexity of the cementing jobs by potentially corroding the set cement sheath. Wells with sustained casing pressure due to poor cementing jobs would causelosses to hydrocarbon reserves, while polluting aquifers with hydrocarbon and well security issues. It was crucial to prevent remedial cementing work, due to unnecessary and costly non-productive time. The objective of primary cementing is to achieve long term zonal isolation across the gas reservoir. A bespoke engineered cementing solution was successfully developed in order to provide a solution to assure long term zonal isolation for shallow gas flow. This paper will describe in detail about the cementing method, how it fits the well situation, the methodology in the slurry design, and thevalidation process in the lab with a novel, uncommon method in the industry, capped off by the post-cementing results analysis. This technology was proven as a solution for shallow gas well cementing and long-term zonal isolation, which is a great referencefor the cementing industry.