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Radonjic, Mileva (Oklahoma State University) | Luo, Guofan (Oklahoma State University) | Wang, Yulun (Oklahoma State University) | Achang, Mercy (Oklahoma State University) | Cains, Julie (Oklahoma State University) | Katende, Allan (Oklahoma State University) | Puckette, Jim (Oklahoma State University) | Grammer, Mike (Oklahoma State University) | King, George E. (GEK Engineering)
A broad range of geological observations are required to characterize any rock mass. These observations range from megascopic to nanoscopic. Megascopic factors include stratigraphy, lithofacies, and structural patterns, whereas key mesoscopic factors include bedding, physical sedimentary structures, biogenic sedimentary structures, and natural fractures (Wang et al., 2019). Microscopic and nanoscopic factors, by contrast, include framework rock composition and fabric, diagenetic alteration of the fabric, organic content, and pore structure (Olabode &Radonjic 2014, Vanden Berg et al., 2019). All of these factors affect the brittleness of sedimentary rocks and their ability to store and transmit hydrocarbons and to be effectively fractured. Finally, no single laboratory technique can capture any of the above properties entirely, as shown by Achang et al. 2017, the permeability interpretation from pressure decay curves depends on the segment of the curve analyzed, duration of data acquisition and permeability depends on particle size and the presence of microfractures in the samples. Accordingly, an integrated characterization approach is required to address the broad range of variables that must be analyzed for unconventional reservoirs.
Mississippian (Lower Carboniferous) Facies Heterogeneity and Distribution within the Mixed Carbonate and Siliciclastic Reservoirs of the Midcontinent STACK play, Oklahoma, USA. This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Austin, Texas, USA, 20-22 July 2020. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract The U.S. Geological Survey completed an assessment of the Anadarko Basin and concluded that in 2010 the estimated technically recoverable undiscovered resources were 495 million barrels of oil, 27.5 trillion cubic feet of natural gas, and 410 million barrels of natural gas liquids. Since then the EIA reported (March 2015) peak oil production at 498,000 barrels/day, with an expectation to contribute to U.S. production growth through low crude oil market conditions. Production forecasts predicted the Anadarko region to grow to over 500,000 barrels/day by end of 2018, and provide higher profit margins for operators with low transportation costs from wellhead to the trade and distribution hub in Cushing, OK. The objective of this study is to evaluate the level of facies heterogeneity including both their lateral and vertical distributions within the mixed carbonate and siliciclastic reservoirs of the Mississippian (Lower Carboniferous) system in order to increase production efficiencies by aiding in determining optimal landing zones, enhancing completion designs, and providing geologic insight into fracture driven interference studies. This study integrates petrographic, sedimentologic, conventional core analyses, and well logs from key points along different transects across the Anadarko Basin leading to the development of core based facies logs. These facies logs provide the quantitative element needed to conduct a geostatistical analysis of facies distributions across the STACK play rather than relying on the qualitative based geological core interpretations alone.
Abbas, Ahmed K. (Iraqi Drilling Company, Missouri University of Science and Technology) | Alhameedi, Hayder A. (University of Al-Qadisiyah, Missouri University of Science and Technology) | Alsaba, Mortadha (Australian College of Kuwait) | Al Dushaishi, Mohammed F. (Oklahoma State University) | Flori, Ralph (Missouri University of Science and Technology)
Coiled tubing (CT) technology has been widely used in oilfield operations, including workover applications. This technology has achieved considerable economic benefits; however, it also raises new challenges. One of the main challenges that were encountered while using this technology is the buckling of the CT string. It can occur when the axial compressive load acting on the CT string exceeds the critical buckling loads, especially in highly deviated/horizontal and extended reach wells. Moreover, this issue becomes more critical when using non-Newtonian fluids. Therefore, the major focus of this study is to identify the frictional pressure loss of non-Newtonian fluids in an annulus with a buckled inner tubing string.
In the present study, a laboratory-scale flow loop was used to investigate the influence of various buckling configurations (i.e., sinusoidal, transitional, and helically) of the inner pipe on the annular frictional pressure losses while circulating non-Newtonian drilling fluids. The experiments were conducted on a horizontal well setup with a non-rotating buckled inner pipe string, considering the impact of steady-state isothermal of laminar, transition, and turbulent flow regions on frictional pressure losses. Six different Herschel-Bulkley fluids were utilized to examine the dependence of pressure losses on fluid rheological properties (i.e., yield stress, consistency index, and flow behavior index).
Experiments showed potential to significantly decrease the frictional pressure losses as the axial compressive load acting on the inner pipe increases. The effect of buckling was more pronounced when fluids with higher yield stress and higher shear-thinning ability were used. In addition, by comparing the non-compressed and the compressed inner pipe, an additional reduction in frictional pressure losses occurred as the axial compressive load increased. However, the effect of the compressed inner pipe was insignificant for fluids with a low yield stress, consistency index, and high-flow-behavior index, especially in the laminar region. The information obtained from this study will contribute toward providing a more comprehensive and meaningful interpretation of fluid flow in the vicinity of a buckled coiled tubing string. In the same manner, accurate knowledge of the predicted friction pressure will improve safety and enhance the optimization of coiled tubing operations.
From spud to plug, the ability for cement to provide an adequate seal with the casing is of paramount importance in preventing the migration of fluids along the wellbore and to the environment. No matter the extremity of a cements compressive or even tensile strength, when debonding between the cement body and steel wall occurs, a micro-annulus is formed and acts as a direct flow path between previously isolated formation fluids. Recent studies using slightly unconventional methods have shown that adding small concentrations of nanoparticle barite and magnetite to a heavy; field ready, class H cement; present an increase in the potential bond strength of the cement.
To show this, laboratory evaluations on the shear and tensile bonding strength of the cement/steel interface were completed for nanoparticle barite and magnetite concentrations of 1%, 3%, and 5% by weight of cement using specially made apparatuses. Each apparatus was designed such that the cement slurry was allowed to set on top of a steel coin that was finely sandblasted to insure that each sample had a similar binding surface and each test used the same displacement rate for consistent loading across each of its samples. The shear bond strength was completed using a modified split core setup that imposed the desired failure plane along the cement/steel interface depending on its orientation. Tensile loading of the samples was applied using a threaded connection point adhered to the top of the set cement sample and connected to the load frame using a specially designed set of brackets.
Using the modified split core setup, it was seen that nanoparticle concentrations of as little as 1% by weight of cement increased the bond strength substantially when compared to the base case for both additives. Additionally, testing of the tensile bond strength further confirmed that the presence of nanoparticles have a significant effect on the cements ability to stay bonded with the inner wall of steel casing. The improvement observed is likely due to the coupled impact of the nanoparticles that act as both a mechanical reinforcement, and a means to reduce the presence of large Calcium Hydroxide (CH) crystals in the hydrated cement body whose irregular shape and fragile nature make it poorly suited for bonding to steel.
Altogether, the addition of nanoparticle barite and magnetite has been seen to introduce new strength to the binding potential of wellbore cement to the steel casing. This translates to a more resilient seal at the cement/steel interface which increases the overall barrier integrity. Whether implemented as a plug or primary cement, the need for an impermeable barrier is absolute.
Alkadi, Nasr (Energy Innovation Center, BHGE) | Chow, Jon (Measurement and Sensing, BHGE) | Howe, Katy (Energy Innovation Center, BHGE) | Potyrailo, Radislav (GE Research) | Abdilghanie, Ammar (Energy Innovation Center, BHGE) | Jayaraman, Balaji (Oklahoma State University) | Allamraju, Rakshit (Oklahoma State University) | Westerheide, John (Energy Innovation Center, BHGE) | Corcoran, John (Measurement and Sensing, BHGE) | Di Filippo, Valeria (Energy Innovation Center, BHGE) | Kazempoor, Pejman (Energy Innovation Center, BHGE) | Zoghbi, Bilal (Energy Innovation Center, BHGE) | El-Messidi, Ashraf (Measurement and Sensing, BHGE) | Zhang, Jianmin (Energy Innovation Center, BHGE) | Parkes, Glen (Measurement and Sensing, BHGE)
This paper presents our progress in developing, testing, and implementing a Ubiquitous Sensing Network (USN) for real-time monitoring of methane emissions. This newsensor technology supports environmental management of industrial sites through a decision support system. Upon detection of specific inputs, data is processed before passing it on for appropriate actions
ABSTRACT: The Gulf of Mexico (GoM) is home to more than 50,000 oil and gas wells with approximately 30,000 wells that are plugged and abandoned leading to concerns of oil and gas leakage where currently, little to no monitoring is performed. The cement used when completing and eventually plugging wells is subjected to harsh conditions leading to failure of the cement due to debonding of the cement to the formation and/or casing, shrinkage of the cement, and chemical degradation in the cement. The goal of this study is to identify and rank the contributing factors of stress development that influence the potential of debonding along the cement interfaces for wells in the Eugene Island OPD in the GoM using staged poro-elastic Finite Element Models (FEM). The results show that the setting stress and the pore pressure in the cement that develop during hydration cause the most potential for debonding whereas the geographic in-situ stress magnitudes and cement mechanical properties have minimal effect on the stress development.
Drilling in the Gulf of Mexico (GoM) started in the early 1900's with primitive rigs connected to land by piers. Today there are over 50,000 oil and gas wells with approximately 30,000 that are plugged and abandoned (P&A) (data.bsee.gov 2018). Many of the P&A'ed wells have been that way for decades leading to concerns of oil and gas leakage. Current P&A practices in the GoM dictate that the well casing must be cut and buried beneath the sea floor (30 C.F.R. §250.1715). If a P&A'ed well is leaking, the leakage would have to travel from the cut casing to the sea floor where it would be diluted and swept away by currents and tides. This combined with the fact that monitoring of P&A'ed wells is not required by the Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE) making it difficult to determine which wellbores are leaking. Thus alternative methods, such as numerical modeling, can be used to evaluate wellbore integrity. However, one major challenge with such alternative methods is creating realistic models with accurately determined input parameters.
ABSTRACT: Shale rocks were first of interest as a source rock for hydrocarbons, and as Caprocks that provide seals for HC reservoirs. More recently their integrity has been investigated in the containment of injected CO2 and as unconventional reservoirs for oil & gas. Hydraulic fracturing has been used to produce hydrocarbons from shale rocks for more than a decade, but the fundamental mechanism to initiate and propagate these fractures remains unclear. The shale rocks are complex and heterogeneous geological material highly impacted by depositional environment, diagenesis and earth stresses. Macro and Microstructure of shale rocks are dominated by distinct laminated layering, which causes the anisotropy in petrophysical and mechanical properties. Due to this heterogeneity, when subjected to a load, both plastic and elastic deformations manifest simultaneously at different degree in different directions, leading to a difference in failure/fracture response of the bulk rock. The objective of this paper is to gain a fundamental understanding of how and where the fractures initiate when the rock is under stress, as in the case of pressure buildup or hydraulic fracturing.
Indentation tests were conducted on two shale formations, Pottsville, AL, and Marcellus, PA, at both micro and nanometer scale on retrieved drilled rock core samples to get the mechanical properties of the bulk and individual mineralogical phases present. Results from indentation showed Pottsville shale sample had overall better sealing properties than Marcellus shale, because of the higher bulk mechanical properties, more uniform grain size, higher rigid grain content, and the potential fracture/deformation healing and re-sealing within few months.
Shale rock can occur either as caprocks for subsurface storage in conventional reservoirs or as unconventional reservoir rocks for hydrocarbon extraction via hydraulic fracturing. With the present shift of the world energy market towards shale oil/gas, more studies are made to understand the behavior of shales in order to optimize reservoir production and prevent ineffective wellbore performance due to fracture closures and ultimate permeability reduction. . Shale formations with low permeability and resilience towards fracture initiation and propagation are likely to be utilized as seals (shale caprock) for carbon capture and nuclear waste storage; while permeability of shale formations which can be significantly enhanced by the formation of hydraulic fractures are more suitable for unconventional hydrocarbon extraction [Bourg, 2015]. For both scenarios, the mechanical properties of the rock are identified as the key factors, because they determine the likelihood of formation of permeable fracture network [Josh, et al, 2012]. Mechanical properties of shale rock strongly depend on mineralogical composition, microstructure, water content, pressure (P), temperature (T), as well as the bedding orientation to the loading direction (strength and elastic properties vary in different directions) [Suarez-Rivera and Fjaer, 2013; Rybacki et al., 2015]. Understanding the effect of these factors on the properties of shale rocks is crucial for both extraction and storage applications.
ABSTRACT: The process of increasing fracture pressure using engineered drilling fluids is called wellbore strengthening. It is possible to push the fracture gradient and generate a wider mud window by reducing filtration into the formation surrounding the wellbore. This goal can be achieved by using a small concentration of barite Nanoparticles (NPs) in drilling fluid. Barite NPs were synthesized using micro-emulsion method. Barite NPs were added to three different water-based drilling fluid systems. Mud weight, plastic viscosity and yield point for each drilling fluid were recorded. An API standard filter press and a High-Pressure High-Temperature (HPHT) filter press were used to investigate the influence of different parameters of filtration, including differential pressure, temperature, permeability, barite NPs size, and concentration. The results show that adding barite NPs to the water-based drilling fluids is an effective approach to wellbore strengthening. A model was developed to predict breakdown pressure based on the filtration reduction and formation permeability. A deepwater well in the Gulf of Mexico was studied to evaluate the effect of wellbore strengthening using NPs. The results show the possibility of reduction of the number of casings required to reach a target.
During the drilling operation, it is important to select safe mud weight with lower and upper limits. With the goal of minimizing risks associated with wellbore instability (including unwanted fracturing the formation that can cause serious consequences), it is essential to establish a minimum safe mud weight while maintaining proper hole cleaning. As a well deepens, the range of the mud safe window narrows due to the convergence of the pore and formation fracture gradient. Therefore, it is crucial to monitor the selected mud weight to make sure that mud density stays in the safe range.
In drilling engineering, wellbore strengthening (increasing the fracture pressure) can be achieved by using engineered drilling fluids. By preventing drilling fluid leakage into the formation and limiting the local increase of formation pore pressure around the wellbore, it is possible to achieve a higher fracture pressure during drilling. For hydraulic fracturing stimulation method, it is desirable to lower the fracture pressure of the formation. Researchers have suggested many different wellbore strengthening techniques including but not limited to the use of different additives in drilling fluids, heating the wellbore to change in situ rock stress distribution around the borehole, and the use of pills for temporarily isolating troublesome zones. By adding thermoset rubber into water-based and oil-based drilling fluid systems, Nayberg et al., 1987 reduced mud loss into simulated fractured formations. Morita et al., 1990 conducted hydraulic fracturing tests on sandstone samples and found that the fracture pressure increased if bridging materials were used. Similar results were reported by Fuh et al. 1992 showing that the use of certain size and specific gravity lost-prevention materials increase fracture breakdown pressure. In three field tests for both shale and sandstone intervals, Aston et al., 2004 designed and used a low fluid loss water-based drilling fluid which increased fracture pressure by forming a stress cage of bridging materials. They stated that wellbore strengthening is a better approach than treating lost circulation events. After studying different techniques, Soroush et al., 2006 concluded that using methods such as grouting, bridging balls, and high-power laser glazing can reduce permeability and increase wellbore strength. Growcock et al., 2009 reviewed different wellbore stabilization technologies available in the industry and suggested that drilling fluid selection and optimization of mud properties are key factors in preventing wellbore instability.
ABSTRACT: Gas leakage through wellbores is one of the major challenges in Oil and Gas Industry related to well cementing and wellbore integrity, whether post CO2 injection or during gas production in hydraulically fractured shales. The inadequate cement bond at the interfaces with formation and/or casing will result in failure of the cement sheath and poor zonal isolation causing hazard to the environment. The mains reasons for poor cement integrity are the drilling fluid contamination, as well as the pipe and casing string corrosions, as both of these create deposition of mechanically inferior and highly porous materials at interfaces. Furthermore, they are big issues in permanent plugging and abandonment as well. P&A requires longer-term isolation comparing to primary cementing. The objective of this paper was to compare the microstructural properties of wellbore cement samples impacted by the drilling fluid contamination versus metal pipe corrosion products. In this research, drilling fluid contaminated, and cement in contact with corroded metal pipe, were compared for changes in chemical composition, and internal structure. Oil-based, synthetic oil and water based types of drilling fluids were applied to the Class H cement slurries (16.4 PPG). Microstructural properties and spatial chemical element distribution were evaluated using Scanning Electron Microscope (SEM), Energy Dispersive X-Ray Spectroscopy (EDS), and Electron Probe Micro Analyzer (EPMA). The results showed that the presence of acid environment and drilling fluid cake would produce leaching of elements and fracture formation, which would result in compromised zonal isolation and wellbore integrity issues.
Permanent plugging and abandonment is completed with a goal to forever seal and isolate the permeable intervals that a wellbore intersects, and prevent the upward flow of subsurface fluids into fresh water aquifers and/or discharge to the surface. Wellbore cementing provides the same function for a wellbore during drilling, completions and production. A stabilized long term sealing is the main parameter to test the success of both wellbore barriers, cement sheath and cement plug. Inadequate well plugging within offshore wellbores releases upward migrating hydrocarbons over the course of decades leading to cumulative damage to surrounding areas, such as the fragile ecosystems surrounding the deep water in the Gulf of Mexico.
Arends, Olivia (Stepan Company) | Seymour, Brian (Stepan Oilfield Solutions) | Benko, Brandon (Stepan Company) | Elshahed, Mostafa (Oklahoma State University) | Yakoweshen, Lynn (Stepan Oilfield Solutions) | Ganguly-Mink, Sangeeta (Stepan Company)
Microbial-induced problems in oil and gas incur high costs and cause severe environmental and safety concerns. Most of these problems are directly caused by surface-adhered bacteria colonies known as biofilms. Distinct populations of bacteria within a biofilm can symbiotically alter surrounding conditions that favor proliferation to the extent that leads to corrosion, plugging, and H2S souring. Biocides are antimicrobial products used to eliminate and prevent bacterial growth. The purpose of this initial study is to measure performance of biocides against anaerobic planktonic and sessile bacteria. The three anaerobic conditions tested were biocide performance against planktonic bacteria, against established biofilm, and inhibition of biofilm growth.
Biocides containing two types of quaternary ammonium compounds and blends with glutaraldehyde were evaluated against sulfate reducing bacteria (SRB) and acid producing bacteria (APB) in both planktonkic and sessile forms. As expected, all of the biocides tested were effective against planktonic bacteria. Quaternary type biocides were found to be particularly effective at controlling sessile anaerobes. Surprisingly, the addition of glutaraldehyde did not appear to provide synergistic benefits and actually had a negative dilutory effect on the performance against biofilms. In all cases, dialkyl dimethyl ammonium chloride (DDAC) was the most efficient biocide in controlling all bacterial forms tested, both planktonic and sessile.