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Direct hydrocarbon measurement on extracts of core and cuttings and SARA (Saturate, Aromatic, Resin and Asphaltene) compositional analysis integrated with mud log and petrophysical data provide a high confidence reservoir saturation assessment and oil-water-contact (OWC) identification where testing and perforation decisions can be timely and cost effectively achieved.
A suite of forty eight (48) core plug and cuttings samples from seven (7) wells were analyzed. SARA composition were determined on extracted samples to assess hydrocarbon saturation and OWC through the reservoir of interest. Log and core data comparison with a vertical well, drilled nearby previously, may help to provide hydrocarbon saturation assessment of the section drilled in the horizontal section. However, despite detailed core studies on the vertical well drilled nearby, encountering surprises in the horizontal section due to the complexity of geology is not un-common. In order to circumvent these surprises, here we propose a cost optimized quasi real time formation evaluation and OWC identification using analytical and interpretive protocol that has proved extremely helpful in X reservoir in an oil field in Abu Dhabi. Data and interpretive protocol adopted in this study, although applied to an appraisal scenario, has equally good application potential for development drilling for the selection of an optimal perforation interval.
The novel integrated approach presented here utilizing mud log, extract yield normalized to rock weight and SARA composition, though present and utilized independently for decades in the industry, has been adopted concurrently to assess hydrocarbon saturation and OWC identification. Coupled with conventional open hole logs, mud log and extracts geochemical data on core and cuttings samples provide a robust perforation or completion interval selection. Such perforation interval selection or isolation of high water zone in a horizontal well scenario is particularly very critical in thin and tight reservoirs where improper well completion may severely impact reservoir performance and project's economics
Koksalan, Tamer (ADNOC Onshore) | Ahsan, Syed Asif (ADNOC Onshore) | Azouq, Youcef (ADNOC Upstream) | Alhouqani, Shamsa Sulaiman (ADNOC Onshore) | Al Blooshi, Ahmad (ADNOC Upstream) | Ali Basioni, Mahmoud (ADNOC Upstream)
Oil leakage, due to well integrity issues of varying proportions, from downhole completions is a common phenomenon despite all measures and adherence to regulations. These leakages potentially could cause environmental damage through surface spill, aquifer contamination and in worst-case scenario loss of human lives. In an offshore setting, impact of well integrity issue can be more severe than in an onshore well due to complex and often costly offshore well operations. Downhole completions including cement quality deterioration occurs with the passage of time due primarily to corrosive nature of hydrocarbons produced from a well. Oil companies perform routine well integrity surveillance by acquiring real time annulus pressure data, cement bond, temperature and sonic logs to assess well integrity and perform remedial measures, if and when, required. Leakage may also occur in a complex pattern from nearby wells and different reservoir than the suspected reservoir and show up in the annulus or eventually on the surface. Whilst, well integrity surveillance data indicates leakage when it occurs, finding the exact source location of leakage is often difficult. Objective of this study was to perform a cost-optimized reservoir to annulus leakage oil correlation using geochemical methods in an offshore well to establish the source of oil in the annulus.
Progressing Cavity (PC) pumps evolved from their industrial pump origins to a diverse range of geometries and configurations that satisfy a variety of oilfield artificial lift applications including several where no other lift systems had proved effective. While these downhole PC pump designs provide options for end users, the numerous products combined with a lack of industry standardization has the potential to make pump selection and application challenging. The first part of this paper describes the fundamental PC pump geometry parameters along with various other design parameters and provides context for how they are incorporated in downhole PC pump design. A second part demonstrates how the PC pump design flexibility can be deployed to address specific operational challenges through a synopsis of the design and field experience of two novel PC pump configurations. The first new configuration uses a modified rotor geometry with alternating sections of interference and clearance fits with a standard stator. Since the clearance sections of the stator do not experience contact and as a result normally no elastomer damage, the associated section of stator remains intact in most cases even after prolonged pumping under problematic operating conditions. After the initial interference sections of the stator have been damaged, an adjustment to the rotor position can be made to the non-damaged section of the stator by lifting the rod string a short distance at surface, thus restoring pumping operation without surfacing the pump. The second novel PC pump configuration employs a modified low eccentricity large cross-section rotor geometry. Potential benefits of this configuration are a strong rotor that is less prone to breaking when operating in highly directional wellbore segments; reduced eccentric pump movement that minimizes rod breaks and vibration above the pump; a rotor profile that when sanded-in pulls free easier at lower safer loads for flushing/coiling; and a wider seal line profile that makes the rotor less prone to severe damage and results in higher salvage rates for rechroming. Several different models of both novel pump configurations have been developed and run in the field to confirm benefits.
Onwumelu, Chioma (University of North Dakota) | Kolawole, Oladoyin (Texas Tech University) | Bouchakour, Imene (University of North Dakota) | Tomomewo, Olusegun (University of North Dakota) | Adeyilola, Adedoyin (Central Michigan University)
The Magnetic Resonance Imaging (MRI) log and the Nuclear magnetic resonance (NMR) are resourceful in addressing various scientific questions in petroleum geology, and they have been universally utilized in estimating total porosity due to its repeatability. Notwithstanding, the field applicability of NMR in lieu of MRI logs to estimate total porosity, have not been fully explored. The objective of our study is to develop a novel correlation between the NMR core analyses performed in the laboratory and the field MRI logs. In this study, firstly, we examined various core samples using 2MHz Geospec NMR core analyzer, and our results are compared to results from magnetic resonance imaging (MRI) log taken at 1MHz. Secondly, we performed a detailed analysis of the MRI logs, and NMR core analysis of Bakken Formation. We then evaluated the petrophysical properties of the investigated cores including its porosity, water saturation, and permeability. Our results show that there is a reasonable degree of concordance between the compared investigated results. The results from our study provided a more efficient correlation between MRI log and NMR core by considering the differences in sample volume and difference in frequency.
The Bakken Formation is one of the most prolific unconventional shale plays in North America (EIA, 2019). This formation was deposited from the Late Devonian to Early Mississippian in the Williston Basin and overlies portions of North Dakota, Montana in the United States, and portions of Manitoba and Saskatchewan in Canadian Provinces (Fig. 1). Bakken consists of four members; the upper and lower member which are black organic-rich shales, the middle member, and Pronghorn members are mixed siliciclastic and carbonates. The Lower Bakken Shale overlies the Pronghorn Member or, where the Pronghorn is absent, it rests uncomfortably upon the Three Forks Formation and overlain by the Lodgepole Formation (Webster, 1984; Meissner, 1978). The upper and lower Bakken are the source rocks while the middle member serves as a reservoir for oil produced from the upper and lower Bakken (Lefever et al., 1991; Nordeng, 2009; Nesheim, 2019) and has low porosity and permeability, particularly for a reservoir rock. Bakken shales exhibit high gammaray response as a result of adsorption of uranium over an extended period from seawater under reducing conditions, hence are easily recognizable and used for correlation purposes. Well-logging tools are used extensively in the petroleum industry to identify physical properties of rocks downhole, for example, resistivity, density which are then converted to provide petrophysical properties of interest (permeability, porosity, oil and gas zone). Nuclear Magnetic Resonance (NMR) is a method used extensively in petroleum geology to total porosity and to measure the pore size distribution (McKenon et al., 1999.)
Tran, Son (University of Alberta) | Yassin, Mahmood Reza (University of Alberta) | Eghbali, Sara (University of Alberta) | Doranehgard, Mohammad Hossein (University of Alberta) | Dehghanpour, Hassan (University of Alberta)
Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant oil-recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1 and a mixture of C1/C2 with the molar ratio of 70:30) HnP experiments on an ultratight core plug collected from the Montney tight-oil formation, under reservoir conditions (P = 137.9 bar and T = 50°C). We used a custom-designed visualization cell to experimentally evaluate mechanisms controlling gas transport into the plug during injection and soaking phases and oil recovery during the whole process. The tests also allow us to investigate effects of gas composition and initial differential pressure between injected gas and the plug (ΔPi = Pg - Po) on the gas-transport and oil-recovery mechanisms. Moreover, we performed a Péclet number, NPe, analysis to quantify the contribution of each transport mechanism during the soaking period.
We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe = 1.58 to 3.03). When the soaking progresses, NPe ranges from 0.26 to 0.62, indicating the dominance of molecular diffusion. The advective flow caused by ΔPi during gas injection and soaking leads to improved gas transport into the plug. Total system compressibility, oil swelling, and vaporization of oil components into the gas phase are the recovery mechanisms observed during gas injection and soaking, while gas expansion is the main mechanism during depressurization phase. Overall, gas expansion is the dominant mechanism, followed by total system compressibility, oil swelling, and vaporization. During the “puff” period, the expansion and flow of diffused gas drag the oil along its flowpaths, resulting in a significant flow of oil and gas observed on the surface of the plug. The enrichment of injected gas by 30-mol% C2 enhances the transport of gas into the plug and increases oil recovery compared to pure C1 cases.
The Spirit River Group in Western Canada has always been difficult to drill and complete due to the presence of natural faulting in shaley formations interbedded with coal. MPD techniques allow the successful drilling of these wells; however, completing these wells has been extremely challenging. On this well, getting liner to bottom without total losses should not have been possible.
To address this, a design that used a three mud system in combination with MPD was utilized. With a diversion sub placed at the heel, the wellbore fluid column consisted of a highly underbalanced drilling fluid in the lateral, a descending column of slightly underbalanced stripping fluid placed in the vertical section, and an overbalanced column of kill fluid backfilled into the annulus from surface.
During the liner run, this three-fluid system design smoothly reduces the hydrostatic pressure at proportional rates to the increase in liner surge. This balances the wellbore at the time the RCD is installed behind the liner. The combination of factors saw full returns to surface during the liner run and, once on bottom, allows the rig to break circulation for the final displacement to completions fluids.
With the successful implementation of this 3-fluid system, the operator was able to drill further, past 22,000’, as it is now possible to run and deploy the liner without expecting the loss of the wellbore's volume of fluid on these tight window wells.
Ten years ago, news reports frequently cited peak oil as a looming problem facing our world. Technology and innovation has since been developed that allows us to tap into rocks that were previously deemed impossible to extract oil from, reversing this trend. The Western Canadian Sedimentary Basin has been a leader in this movement with entrepreneurs using new technology to develop our resources in a safe and reliable way. Ten years ago, news reports frequently cited peak oil as a looming problem facing our world. Technology and innovation has since been developed that allows us to tap into rocks that were previously deemed impossible to extract oil from, reversing this trend.
This paper presents a state-of-the-art review of scale-inhibitor-analysis techniques and describes how these techniques can be used to provide cost-effective scale management. Calcium sulfate (CaSO4) in the form of gypsum and anhydrite is one of the more prevalent evaporite minerals typically found in the carbonate rocks of the western Canadian sedimentary basin (WCSB).
This course will provide a general overview of current and emerging heavy oil recovery methods with emphasis on field experiences in Alberta and steam assisted gravity drainage (SAGD). Participants will learn about the concepts, field development, reservoir performances, applicability, challenges, and issues of the various in-situ recovery methods. Discussions in this session focus on carbonate reservoir recovery processes and mechanisms, from field experiences to laboratory observations. Topics include thermal casing and cement, Sand control, well intervention, and wellbore simulations. This session addresses the fundamentals and tools for predicting benefits of and usage of solvent for enhanced recovery.Â Topics include both water-soluble solvents and the more traditional hydrocarbon solventsâ€™ viscosity, relative permeability, heat and mass transfer, sampling, and reservoir performance prediction.
Advanced machine-learning methods combined with aspects of game theory are helping operators understand the drivers of water production and improve forecasting and economics in unconventional basins. The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. Several well-stimulation products and techniques have been seen to benefit well productivity from recent field trials and implementations in carbonate reservoirs, including simpler acid fluid systems, integrated work flows, and coiled-tubing bottomhole assemblies. Researchers use novel methodology to measure the thermo-electric properties of native crude. Business Development VP Kirstie Boyle joins The SPE Podcast to talk startups.