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SPE, through its Energy4me programme, will present a free one-day energy education workshop for science teachers (grades 8–12). A variety of free instructional materials will be available to take back to the classroom. Educators will receive comprehensive, objective information about the scientific concepts of energy and its importance while discovering the world of oil and natural gas exploration and production. Energy4me is an energy educational public outreach programme that highlights how energy works in our everyday lives and promote information about career opportunities in petroleum engineering and the upstream professions. SPE’s Energy4me programme values the role teachers and energy professionals play in educating young people about the importance of energy.
A successful rigless subsea stimulation was executed during 2018, with the intervention performed on three target wells offshore of Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid-stimulation and scale-squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open-water hydraulic access system, using a hybrid coiled tubing downline (HCTD). Access to the subsea trees was enabled by a novel choke-access technology, allowing for a flexible, cost-efficient, and low-risk intervention. The intervention system was installed on a multiservice vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, accommodating potential changes in the treatment plan without impact to critical path-stimulation activities.
The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in-house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors.
The challenges faced during execution included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. A collaborative solution was developed that combined the resources of the service provider, inclusion of performance-based elements within the contract, and delivery of an efficient and flexible well-access technology that supported rapid mobilization and alleviated operational risk.
Post-stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity-index factor gain of 3.4. These results confirm the appropriateness of open-water hydraulic access using coiled tubing (CT) for performing cost-effective stimulations on complex subsea wells.
Han, Xiaodong (China University of Petroleum, Beijing and CNOOC) | Zhong, Liguo (China University of Petroleum (Beijing)) | Liu, Yigang (Tanjin Branch of CNOOC) | Zou, Jian (Tanjin Branch of CNOOC) | Wang, Qiuxia (Tanjin Branch of CNOOC)
Summary Heavy-oil resources whose underground oil viscosity is greater than 350 mPas is abundant in the Bohai oilfield. Because of the lack of effective exploitation technology, production performance with cold-production methods was not satisfactory. Seeking an effective method of heavy-oil exploitation, the multiple thermal-fluid stimulation was proposed and studied, in which hot water or steam mixed with carbon dioxide (CO 2) and nitrogen (N 2) would be injected into the formation for heating the oil and improving heavy-oil production. Considering the limitation of the offshore platform, a miniaturized multiple thermal-fluid generator was designed and developed. Integrated technologies such as seawater desalinization, heat insulation, and anticorrosion methods were also studied and developed. A pilot test of multiple thermal-fluid stimulation was conducted in Nanpu oilfield, starting in 2008. Until now, the pilot test has lasted for more than 10 years, and a total of 27 cycles of multiple thermal-fluid stimulation have been carried out. The cumulative oil produced by multiple thermal-fluid stimulation reached approximately 5.710 5 m 3, and the incremental oil production is approximately 2.610 5 m 3 . The performance of oil production was satisfactory. With the increase of the stimulation cycles, a gas-channeling problem emerged and resulted in a decrease in the oil-production rate. New methods need to be studied and used for further enhancing oil recovery in Nanpu oilfield at the late stage of multiple thermal-fluid stimulation. Introduction Heavy-oil resources are widely distributed around the world, and with the rapid depletion of conventional oil resources, economical and efficient development of heavy-oil resources is one of the most effective ways to meet future energy demands (Mohammadpoor and Torabi 2012; Ehtesabi et al. 2014; Hou et al. 2016). Based on decades of scientific research and field tests, both thermal and nonthermal recovery methods have been developed and applied to heavy-oil exploitation (Nasr and Ayodele 2005; Zhong et al. 2013; Feng et al. 2011). For cold production, waterflooding and chemical-flooding methods are the most common for heavy-oil production (Feng et al. 2010, 2013; Wang et al. 2013a; Wu et al. 2016b; Guo et al. 2018).
Implementing deep-offshore Enhanced/Improved Oil Recovery (EOR/IOR) is not an easy task. Bigger reservoirs, larger well spacings, injection/production/logistics constraints and difficulties to quantify benefits are some of the challenges that may be faced.
This paper presents the status and future vision for the main offshore EOR/IOR research and field application initiatives of a brazilian Operator. Most promising technologies and issues will be described. Overall research structure, as well as adopted strategies to test and implement those techniques will be addressed. Difficulties eventually faced will be mentioned.
The most promising methods in terms of water-compatible EOR are customized-composition waterflood, novel conformance control solutions and optimal reservoir management. Regarding gas-based technologies, the focus is on WAG flood, foam, subsea gas/liquid separation/reinjection and gas injection optimization.
Ismail, Mohammad Sazwan (PETRONAS Carigali Sdn. Bhd.) | Yahia, Zaidil (PETRONAS Carigali Sdn. Bhd.) | Rozlan, M Rizwan (PETRONAS Carigali Sdn. Bhd.) | Bakar, Mohd Farris (PETRONAS Carigali Sdn. Bhd.) | Amsidom, Amirul Adha (PETRONAS Carigali Sdn. Bhd.) | Chaemchaeng, Parvinee (Baker Hughes) | Zhafrael Mohammad, Rafael Mohammad (Baker Hughes)
Controlling sand has been one of the most difficult challenges in oil production in Upstream Malaysia operations. Conventionally, Cased Hole Gravel Packs (CHGP) or Open Hole Gravel Packs (OHGP) are installed to prevent sand from being produced with the oil to the surface facilities. However, both methods require massive operations and high cost which impact the overall economics of the project.
This paper summarizes the technology evaluation of Shape Memory Polymer (SMP). This includes the working philosophies, candidate selection, risk identification and mitigation plan, and success criteria developed for this technology. Common gravel packing technique is accomplished by packing gravel in the annulus between the screen and formation sand face, where the gravel acts as a barrier preventing the migration of the formation sand. The new technology does exactly the same task by expanding SMP which conforms to the sand face. The only difference, in gravel packing, the contact medium with the sand face is the gravel whereas in this technology the contact medium is the SMP. The operational sequence is very similar to the installation of Open Hole Stand Alone Screens (OHSAS). From the evaluation, one well was identified by the team at BS field for piloting this technology. The well will be part of a development campaign executed in Q2 2020. Details of the well design and scope will be shared briefly, as well as a commercial comparison between conventional sand control methods and SMP.
The pilot test at BS field will be discussed including technology evaluation, candidate selection, well completion design, risk mitigation and others. Several case histories and current available field implementation are also taken into consideration to properly plan the pilot test. The success criteria outlined would help to oversee the performance and continuous monitoring of the system before it can be declared a success. Potential candidates for replication of this technology have also been identified within the Operator's company in the near future.
The possible pilot test for this technology is the result of strong and good collaboration between the Operator and Service Company. If it is a proven success, this technology will become a game changer for downhole sand control in the petroleum industry which will be able to maximize production and save operational expenditures, while ensuring the highest reliability.
In subsea environments, using large-bore/high-rate well designs is often a key contributor to the economic recovery of hydrocarbon resources. Their use is a necessity for accommodating the huge production capacity of the reservoirs they penetrate, with the major benefit of minimizing the number of wells necessary to develop a subsea field. The enthusiasm for using such well designs, however, must also be tempered by a clear understanding of the considerable well control risk they introduce—that risk being an increased level of difficulty in bringing such a well under control if a blowout were to occur. It is common that multiple relief wells, with their inherent complexities and time investment, would be simultaneously required to bring a big-bore blowout under control. The discussion of this fact is, though, not a common topic in industry literature. Instead, capping stacks have been more the focus. Much recent attention has been trained on ensuring that capping stacks are a viable method for quickly responding to a high-rate subsea blowout. This makes sense in light of the simpler, and publicly more palatable, concept of rapidly installing a capping stack on a blown-out subsea well. Still, a capping stack is only as reliable as the wellhead it must connect to. It is because subsea wellheads have such a high chance of being damaged during a blowout that relief wells will always be relied on as the ultimate backstop for ensuring that a subsea blowout can be brought under control.
This reliance on relief wells, as they are traditionally envisioned, has limitations though when addressing a high-rate subsea blowout. Any subsea relief well will have inherent limitations resulting from the architecture of choke and kill lines (flow restrictions) and that of the crossover piping at the blowout preventer (BOP; erosion concerns). In the world of high-rate subsea blowouts, these limitations can sometimes translate into multiple relief wells being required to inject fluid at the rates necessary to affect a dynamic kill. However, the simultaneous use of multiple subsea relief wells to dynamically kill a single blowout has only been tried once in the industry’s history. As a result, some countries require that stopping a blowout must be possible by drilling only one relief well.
In this paper, we describe methods that can be implemented to transcend traditional relief well limitations via using a relief well injection spool (RWIS), with the ultimate goal of dynamically killing a subsea big-bore blowout using a single relief well. The technique varies with water depth. In both shallow-water (826 ft) and deepwater (8,260 ft) environments, the techniques are presented and analyzed that will allow using a single subsea relief well to perform a dynamic kill using 15 lbm/gal drilling fluid injected at 238 bbl/min. This particularly severe scenario, based on a big-bore gas well development in Western Australia, is chosen so that our results will have applicability to most subsea well control events that might arise in the future.
Posenato Garcia, Artur (University of Texas at Austin) | Jagadisan, Archana (University of Texas at Austin) | Hernandez, Laura M. (University of Texas at Austin) | Heidari, Zoya (University of Texas at Austin) | Casey, Brian (University Lands) | Williams, Richard (University Lands)
Summary Reliable formation evaluation in organic-rich mudrocks requires integrated interpretation of well logs and core measurements. More than 80% of the Permian Basin wells have incomplete data sets, lacking photoelectric factor (PEF) or other logs required for reliable formation evaluation in the presence of complex mineralogy. Hence, we develop a novel workflow to reliably estimate rock properties in wells with incomplete data to enhance reservoir characterization and completion decisions. We propose to use integrated rock classification for enhanced physics-based assessment of rock properties in wells with missing data; combine field-scale geostatistical and machine learning methods to reliably reconstruct missing PEF logs with a confidence interval through a rock-type-based approach, which is a unique contribution of this work; and quantify the uncertainty in estimates of petrophysical properties. We performed a preliminary field-scale formation evaluation on wells with triple-combo logs (more than 70 wells). Next, we performed an initial rock typing and reconstructed the missing PEF logs by combining supervised neural networks with geostatistical analysis on a rock-type basis. We then used an unsupervised neural network method to improve the rock classification based on the updated estimates of petrophysical and compositional properties after PEF reconstruction. The combined rock classification and PEF reconstruction was performed iteratively to improve the multimineral analysis results in all wells with missing data. We successfully applied the new workflow to 20 wells in blind tests. The reconstructed well logs agreed with the actual measurements with relative errors of less than 10%. The new workflow extends the boundaries of reliable formation evaluation, enabling accurate reservoir characterization and completion decisions by enhancing evaluation of wells with missing data. The proposed method can also be applied to wells with other types of missing data.
We present an integrated interpretation of microseismic, treatment, and production data from hydraulic-fracturing jobs carried out in two adjacent wellpads in the Horn River Basin, northeast British Columbia, Canada.
We conclude that poor correlation coefficients (R2) in crossplots of normalized production rate vs. the product of stimulated reservoir volume (SRV) and porosity and total organic carbon (TOC) (SRV × φ × TOC) indicate pressure interference between wells or wellpads. Good correlation coefficients in the same crossplots indicate lack of interference.
The SRV × φ × TOC product reflects the hydrocarbon pore SRV because there is a relationship between TOC and hydrocarbon saturation in shales (Lopez and Aguilera 2018). Our results suggest that natural-fracture networks have an important effect on well connectivity and on the spatial distribution of microseismic data. Connectivity between wellpads occurs through a network of pre-existing natural fractures, which are approximately perpendicular to the least principal compressive stress in the area.
This conclusion is supported by data analysis from Wellpads I and II in the Horn River Basin. Wellpad I includes eight wells that were drilled and fractured in the Muskwa and Otter Park formations (four wells in each formation) in 2010. Wellpad II includes three wells drilled and fractured in 2011 in each of the three shale formations, Muskwa, Otter Park, and Evie. There is a 1-year interval between fracturing on the first and second wellpads.
The data analysis includes evaluation of magnitudes, b-values, moment-tensor inversion (MTI), and the spatial and temporal distributions of three-component microseismic events recorded during more than 200 stages of fracturing by multiwell downhole arrays. We analyzed Gutenberg-Richter frequency/magnitude graphs for each fracturing stage, and with proper integration of b-values, fracture-complexity index (FCI), MTI information, and treatment data, we distinguished hydraulic-fracturing-related events and events associated with slip along the surface of natural fractures. The results are compared with 5- and 4-year gas-production data in Wellpads I and II, respectively.
Identification of natural fractures and information about interactions between hydraulically fractured wells are both essential for optimal well placement and completion, reservoir characterization, SRV calculation, and reservoir simulation. This study presents a distinctive insight into the integrated interpretation of microseismic events and production data to identify the activation of natural fractures and interference between the hydraulically fractured wells. The methodology developed in this study is thus related to production engineering, but examines it from the point of view of microseismic data.
Li, Yingcheng (Sinopec Shanghai Research Institute of Petrochemical Technology) | Kong, Bailing (Sinopec Henan Oil Field Company) | Zhang, Weidong (Sinopec Shanghai Research Institute of Petrochemical Technology) | Bao, Xinning (Sinopec Shanghai Research Institute of Petrochemical Technology) | Jin, Jun (Sinopec Shanghai Research Institute of Petrochemical Technology) | Wu, Xinyue (Sinopec Shanghai Research Institute of Petrochemical Technology) | Guo, Yan (Sinopec Henan Oil Field Company) | Liu, Yanhua (Sinopec Henan Oil Field Company) | Wang, Yanxia (Sinopec Henan Oil Field Company) | He, Xiujuan (Sinopec Shanghai Research Institute of Petrochemical Technology) | Zhang, Hui (Sinopec Shanghai Research Institute of Petrochemical Technology) | Shen, Zhiqin (Sinopec Shanghai Research Institute of Petrochemical Technology) | Sha, Ou (Sinopec Shanghai Research Institute of Petrochemical Technology)
Recently, novel mixtures of anionic/cationic surfactants that produced low critical micelle concentrations (CMCs) of 3.5010 -4 wt%, ultralow interfacial tension (IFT) of 10 -4 mN/m, high oil solubilization of 23, and low adsorption of 0.27 mg/g sand were developed in the laboratory for a mature sandstone reservoir with characteristics of high temperature of 81 C, high water cut of 97.8%, high recovery factor of 53.3%, and low-acid oil of 0.021 mg/g potassium hydroxide (KOH). Coreflooding results indicated that alkali/surfactant/polymer (ASP) flooding with a preslug of crosslinked polymer (CP) increased oil recovery by 24.2% of original oil in place (OOIP) over the waterflood under the optimal chemical formulation. Since January 2012, the first field application of ASP flooding in the world with highly efficient mixtures of anionic/cationic surfactants was performed for a high-temperature, highwater-cut mature sandstone reservoir to demonstrate the potential of the novel surfactant to recover residual oil from as high as 53.3% recovery factor of reserves. ASP slug and CP slug for conformance control were alternately injected. The water cut decreased from 97.9 to 90.2% and the estimated ultimate oil recovery can be increased by 14.2% of OOIP and yield up to 67.5% of OOIP. Introduction After nearly 40 years of waterflooding, most of the oil fields in east China have entered the late development stage with high water cut, high recovery factor of reserves, and low oil-production rate, showing a typical low economic feature of mature oil fields. It is inevitable to develop new oil-production techniques for EOR to replace waterflooding. ASP flooding is an especially attractive and economically viable technology when used in reservoirs that contain "active oil" consisting of petroleum acids, which has proved to be effective in enlarging sweep volume, as well as improving displacement efficiency (Wang et al. 1997). ASP flooding has been extensively tested and applied in China and worldwide with significant EOR performance, such as Daqing Oil Field with a temperature of 45 C (Cheng et al. 2008; Li et al. 2008; Zhu et al. 2012), Shengli Oil Field with temperatures of 68 to 69 C (Wang et al. 1997; Qu et al. 1998), and a Petroleum Development Oman oil field with a temperature of 46 C (Stoll et al. 2011).
In certain situations, it is necessary to obtain a reliable measurement for connate water saturation (Swc) in an oil reservoir. The single well chemical tracer (SWCT) method has been used successfully for this purpose. The SWCT method has been used successfully for this purpose in six reservoirs. The SWCT test for Swc usually is carried out on wells that are essentially 100% oil producers. The procedure is analogous to the SWCT method for Sor, taking into account that oil is the mobile phase and water is stationary in the pore space.