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When determining a slurry's characteristics and performance, these testing procedures are recommended: The methods of testing cement for downhole application are based on performance testing. Testing methods are usually performed according to API specifications, though specifically designed and engineered equipment or tests are also used. The choice of additives and testing criteria is dictated primarily by the specific parameters of the well to be cemented. Performance testing has proven to be the most effective in establishing how a slurry will behave under specific well conditions. There is no direct means of predicting cement performance from the properties of cement, and no technique has yet been established that would correlate cement composition and cement/additive interaction with performance.
ExxonMobil Upstream Research Company (EMURC) recently completed a subsea technology development and qualification program that included performance testing of an inline electrocoalescer device supplied by FMC Technologies (FMC). This paper will summarize the results from these performance tests. Although heavy oil has been processed onshore successfully for many decades, processing heavy oil in deepwater, subsea, or Arctic fields is extremely challenging. One key challenge is oil/ water separation, in which physical separation is constrained by the high viscosity of the crude and the narrow density difference between oil and water. Installing conventional electrostatic coalescers or dehydrators is often not economical or is impractical at remote locations.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196172, “Unleashing the Power of Smart Particles for Completion Diagnostics: Advancing the Production-Flow-Profiling Technology With Subatomic Fingerprints and Big-Data Analytics,” by Talgat Shokanov, SPE, and Pavel Khudorozhkov, QuantumPro, and Adilkhan K. Shokanov, Abai University, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. This paper describes a smart-tracer-portfolio testing and design solution for multistage hydraulic fracturing which will, write the authors, enable operators to reduce operating cost significantly and optimize production in shale wells. The technology combines recently developed smart tracers with advanced subatomic measurements in an automated process with stringent quality control that assures precise tracer addition onsite and provides accurate and actionable completion diagnostics results at a fraction of the cost of production-logging testing, distributed temperature testing, or distributed acoustic sensing. Introduction Multistage hydraulic fracturing operations costs - including high-pressure pumping, proppant, and fluid - ranged from $2.9 million to $5.6 million per well in a typical US shale well in 2018, representing close to 60% of the total drilling and completion cost for each well. Yet industry studies reported that up to 50% of the clusters and stages and up to 40% of the fracture net-works do not produce in the current geometric factory-mode-completion approach, leading to estimates that up to 40% of the drilled and completed shale wells in North America alone could be uneconomical. Additionally, interactions between fractures in adjacent horizontal wells, and the costly negative effects of these interactions, have become the focus of much discussion and debate within the technical community. The impetus for this attention has been the effect of these interactions on productivity and the mechanical integrity of the parent wells. These issues drive the need for oil and gas operators to have more-accurate, affordable, and timely data on the performance of individual fracturing stages, measured intrawell communication, and temporary and long-term frac/frac connections to enable improved decision-making and optimization of multistage hydraulic fracturing operations as well as overall field development. The complete paper describes smart tracer technology, including a patented portfolio and fracturing-/completion-optimization work flow; laboratory testing and performance analysis; and integration with completion diagnostics. Smart Tracer Technology To control the effectiveness of multistage hydraulic fracturing stimulation treatments, it is essential to use special tracing methods based on the addition of the labeled substance to the proppant, water, or gas, and monitor the release of tracers with flowback water and produced oil and gas from the current well or nearby observation wells. Currently, conventional water- and oil-soluble chemical substances with fluorescent properties and ionic, organic materials, or radioactive isotopes, are used as the tracers. Tracers with fluorescent properties and ionic and organic materials are high-cost, limited to chemical-measurement techniques at a molecular level, and often have reported false-positive results for long-term communication. Environmental regulations in many countries prohibit the use of radioactive tracers (i.e., radioactive isotopes) because they pollute the environment and could contaminate subsurface layers.
Abstract Current multistage hydraulic fracturing operations in shale are costly, environmentally challenging and inefficient. Multistage hydraulic fracturing operations already represent close to 60% of the total drilling and completion cost for each shale well. The industry studies reported that based on data evaluated in multiple shale basins in North America alone that up to 50% of the clusters and stages do not produce in geometric completion design. Shale E&P operators need more accurate, cost-efficient, timely and actionable data on the performance of individual fracturing stages and intra-well communication to enable improved decision-making and optimization of multistage hydraulic fracturing and completion strategy, as well as overall field development. This paper will describe a revolutionary smart tracer portfolio testing and design for multistage hydraulic fracturing stimulation. The technology enables the next generation of smart tracers coupled with advanced sub-atomic measurements that significantly reduce the completion cost and double the efficiency of the hydraulic fracturing treatments. An automated process with stringent quality control assured precise tracer addition onsite and provided accurate and actionable completion diagnostics results at fraction of the cost for high-cost measurements (e.g., PLT, DTS & DAS). The integration of smart tracer portfolio with intelligent-completion diagnostics for E&P customer enabled by performance-flow-profile data. This data used to optimize completion strategies, achieve optimal production per foot, and reduce completion cost. Follow-up big-data analytics and 3D fracture-modeling delivered accurate, calibrated, actionable, and cost-effective completion-diagnostics results. Since tracer data are captured over several months, E&P operators are captured access to continuous flow profiling data to optimize well performance routinely when new completion-diagnostics results are received. This will enable E&P operators to significantly reduce operating cost and optimize production in shale wells.
Abstract To maximize return on investment, many operators choose to re-fracture existing wells as an economic alternative to drilling new wells. While it may improve ultimate recovery, re-fracturing of wells with multiple producing zones can be challenging. Several techniques are available in the market place; each having its own limitations and benefits. The technology discussed in this paper, already implemented in the Western Hemisphere, uses a guar-based gelled fluid for temporary zonal isolation in the annulus. The need for a cost-effective solution for re-fracturing, without using a packer or other downhole isolation tool was identified in the Changqing oilfield in China. The objective was to prove the concept of using a gelled annular isolation technology for re-fracturing in this oilfield for applicability in the Asia Pacific region. Two candidate wells were selected for re-fracturing based on previously completed methodologies and observed production declines. A two stage vertical well was selected for proof of concept. The original completion used a 5 ½-in. casing, applying multi-stage sand jetting fracturing. The application of the gelled polymer system for re-fracturing utilized the 5 ½-in. casing as an outer tubing and implemented a 3 ½-in. inner string to create an annular space for isolation. The gelled fluid was pumped into the annular space between the inner tubing string and the original casing to isolate existing perforations in the two stages. After the re-fracturing treatment was completed, the gel was broken down and the inner string removed. Before the job was pumped, laboratory testing and simulation concluded that the gelled fluid would be placed within the pump time of the job and hold for the expected time frame of the fracturing operations. This testing provided detailed operational guidelines on placement time, pump rate, fluid shear rate at bottom hole temperature within the constraints of the wellbore architecture before committing to pump the job. The fluid was successfully placed and maintained isolation during fracturing stages. The inner string was removed from the hole following the breaking of the isolation fluid. The novelty of this work included the application of using a guar-based gelled fluid as a temporary annular isolation pill in a re-fracturing application in China. In addition, this work proved that an inner completion string could also be temporary and therefore removed after the job was completed to ensure that maximum access to the reservoir was achieved. Finally, this is the first cost effective and simple re-fracturing methodology introduced to this area of the Asia Pacific region.
Performance test provides important information about whether a newly constructed pipeline can achieve the design capacity and transportation efficiency. The field performance test also provides mechanical performance correction factors for compressors as part of the commissioning procedure of natural gas transmission pipelines. The EPC contractors are usually asked to ensure that the pipeline can achieve the delivery pressures and flow rates under the protocols agreed upon. Pipelines are normally designed to achieve certain flow rates in different phases. However, it is not uncommon to see pipelines falling short on gas supply or user demand during the time period that the performance test is scheduled for. The available pipeline inlet pressure and flow rate are lower than the guarantee conditions described in the performance test protocols. The quality of the gas supply may also create unexpected problems on the interpretation and evaluation of the performance test results. Therefore, it is necessary to conduct the performance test at lower pressures and lower flow rate conditions. This paper presents the methodology, strategy, procedure as well as a real life example of a simulation based performance test of a gas pipeline. The method presented offers a practical tool to validate pipeline performance by evaluating the fundamental physical parameters. This method can also be used in assessing the pipeline hydraulics conditions for potential corrosion issues (ID change), roughness changes, BSW deposition or other issues influencing pressure drops in the pipeline.
INTRODUCTION AND BACKGROUND
Performance test is an important part of the commissioning procedure of natural gas transmission pipelines after their construction. The EPC contractors are responsible of ensuring the pipeline can achieve the delivery pressures and flow rates under the protocols agreed upon. Pipelines are normally designed to achieve certain flow rates in different phases. However, it is not uncommon to see pipelines falling short on gas supply during the time in which the performance test is scheduled. During the economic down turns, the pipeline users may also have difficulty accepting the gas at the flow rate required to achieve the pipeline guarantees. In these circumstances, the available pipeline inlet pressure and pipeline flow rate are lower than the guarantee conditions described in the performance test protocols. The quality of the gas supply may also create unexpected problems in the interpretation and evaluation of the performance test such as the presence of black powder. Therefore, it is necessary to conduct the performance test at lower than anticipated pressures and flow rate conditions. The question is how to assess whether the pipeline performance will achieve the guarantees with the data collected at a lower pressure and lower flow conditions? The answer lays in the assessment of the pipeline parameters using measurement data at lower pressures and flow rates, along with gas pipeline hydraulic simulations at guarantee conditions. This paper presents the methodology, strategy, procedure as well as a real life example of a simulation based performance test of a gas pipeline.
This paper describes how one company developed and implemented a risk-based integrity management system and applied it to operated facilities within the Gulf of Mexico. The challenges of maintaining integrity of offshore assets change constantly throughout the life of a facility. The adoption of an Integrity Management System that integrates both risk-based and prescriptive practices can allow an operator to identify changing integrity threats and apply proactive mitigation strategies in good time. Successful use of an IMS can enhance safe operation and regulatory compliance while maintaining up time during declining production. The paper describes the challenges faced in applying these techniques within the Safety and Environmental Management System regulatory regime and Gulf of Mexico operating culture and reviews Lessons Learned in developing and implementing the Integrity Management Systems The paper describes how the IMS facilitated the assessment of platform condition and remaining life and how this in turn influenced the remediation requirements and subsequent maintenance and integrity activities required to facilitate life extension.
Abstract Hydraulic fracturing is widely used as a well stimulation technique to enhance the productivity of a well by creating fractures in the formation. In hydraulic fracturing, crosslinked fluids are often used to propagate the fracture in the reservoir and to carry the proppant into the fracture to complete a treatment as it is designed. The fluids should possess adequate viscosity, and this can be achieved by use of crosslinkers. The borate-containing mineral ulexite is sparingly soluble in water, and for use as a crosslinker in field operations there is a need to suspend the ulexite, either in aqueous or organic media, for improved operational feasibility. Various suspending aids, such as polymers and clays, can be used to keep the borate ion suspended in the liquid carrier package. For example, existing hydrocarbon-based ulexite slurries suffer from particle settling issues that can lead to operational issues In contrast, the water-based (WB) suspension media can be formulated using environmentally acceptable viscosifiers as suspending agents, along with an aqueous salt solution (i.e., brine) as a carrier fluid to develop a suspension package for ulexite particles. The viscosifiers and brine chosen for the suspension helps to achieve a pour point of −20°F for cold weather use. This paper demonstrates the laboratory investigation of an aqueous suspension for borate minerals that has good suspension stability in both an extreme cold and hot atmosphere. These suspensions exhibited good suspendibility of borate minerals after 24 hours at 80°F. This approach prolongs the shelf life of crosslinkers by essentially eliminating the ulexite settling. The aqueous suspension package remains pourable and shows good thermal resistance after more than a week. Moreover, the aqueous-based crosslinker package is readily used for “on-the-fly” operations. Performance testing of fracturing fluids using the aqueous borate suspension was performed further at different temperatures and compared to a fluids prepared from a crosslinker that has been previously used, and the crosslinked polymers showed excellent rheological behavior up to 275°F.
Abstract The Oil and Gas gathering and processing facility of Kuwait Oil Company was built with a nameplate capacity of X MBOPD with 50% water cut. However, the facility was operating with a water cut of 35% since its commissioning in year 2011. This comprehensive technical study was conducted to evaluate possibility of increasing oil processing capacity of this facility in line with current lower water cut and other operational flexibilities available in the facility without utilizing its design margin. This paper shares an innovative approach to increase name plate capacity of oil and gas processing facility utilizing available operational flexibility and operational margins with minor modification. It shares a case study where facility capacity is increased by around 19% without utilizing design margins of equipment or pipeline. Such approach can easily be applied to all similar facilities across oil & gas industry. The study confirmed that facility name plate capacity can be revised from X MBOPD (with 50% w.c) to X+32 MBOPD (with 45% w.c). It is observed that minor modification in control loop of separator to utilize three phase separator as two phase separator, lower water cut of the feed stream and margin available in feed specification of Desalter trains are major contributors to get leverage in increasing name plate capacity of facility. The paper provides detailed guideline for such out of the box technical evaluation of facility to operate it at higher capacity without any major modifications which will result in significant financial / production gains for any organization.
Gul, Kamran (ExxonMobil Upstream Research Company, Houston, TX, USA) | Grave, Ed (ExxonMobil Upstream Research Company, Houston, TX, USA) | van Wingaarden, Hubert (Advanced Separation Company (ASCOM) BV, Netherlands) | Tienhaara, Mika (Advanced Separation Company (ASCOM) BV, Netherlands)
Abstract ExxonMobil Upstream Research Company (EMURC) conducted a comprehensive laboratory testing program of a produced water de-oiling system primarily targeted for subsea applications. The test program included performance evaluation as well as durability testing of a two-stage mixed-flow de-oiling hydrocyclone technology. The objectives of the test program were to evaluate the separation performance of two system configurations i.e. decoupled and integrated hydrocyclones stages, to understand the overall system integration effects on the performance, and to determine system sustainability to sand loading. Subsea produced water treatment in deeper water applications requires robust, reliable and compact separation equipment. The performance testing confirmed the feasibility of a multi-stage mixed-flow hydrocyclone system for subsea applications and demonstrated that, within a given operating envelope, the system can treat challenging produced water streams with high oil-in-water (OIW) content of up to 5%, reducing it to a few hundred ppm level. In addition, the issue of turndown can be addressed by designing the de-oiling system with multiple parallel banks of liners. The de-oiling system testing was conducted with light and heavy crude oils, of gravities of 36 °API and 19 °API respectively, to map performance characteristics of a two-stage system with the first hydrocyclone stage of bulk oil removal and the second stage of water polishing. Variations in test conditions such as the flow rate, temperature, inlet oil concentration and the reject ratios were introduced to establish optimal operating ranges for each stage as well as for the system. The performance of the decoupled and the integrated system was evaluated by determining separation efficiency break-points at different operating conditions. Accelerated sand erosion tests were performed on a dedicated sand erosion test loop to evaluate different erosion resistant coatings for hydrocyclone liners. The erosion tests helped identify a promising coating solution that can withstand continuous sand loads for long-term operations. The test program demonstrated that a two-stage mixed-flow hydrocyclone de-oiling system can meet challenging subsea produced water treatment and reinjection requirements over a wide range of operating conditions. The paper presents the key results of the overall performance tests as well as the results of sand erosion testing of the hydrocylone liners with different coatings.