Billion Barrels Of Oil Research Articles

Lateral Completions a Boon for Haynesville Extension

There is an old adage in the oil patch: The best place to find oil … is in an oil field. The same holds for natural gas. The Deep Bossier gas play of east Texas spawned some impressive field discoveries in the early to mid-2000s, such as the Amoruso and Savell fields in Robertson County, Texas. Another big find, Hilltop, lies just to the east in Leon County. Wells tap into the Deep Bossier at depths between 15,000 and 20,000 ft. They intersect overpressured shale and sandstone formations a few thousand feet thick. These conventional, vertical wells were challenging to drill, but often the payoff merited the difficulty and the associated cost as many would come online producing 20 MMcf/D or more of natural gas once completed. A few even bested 50 MMcf/D. The Haynesville Shale of east Texas and western Louisiana has been a gas tank for operators like Shell, BP, Chevron, Chesapeake, and others since it came into prominence around 2008. Even though some of these players have exited, it reached new highs in March 2023, averaging 14.5 Bcf/D, 10% more than the 2022 annual average of 13.1 Bcf/D, according to data from Enverus. Haynesville natural gas production currently accounts for about 14% of all US dry natural gas production. It is the third-largest shale gas-producing play in the US, behind the Marcellus play in the Appalachian Basin and the Permian play in west Texas and New Mexico. The linchpin of both plays is their robust natural gas potential. In 2017, the US Geological Survey (USGS) estimated the Bossier Formation contained 2.9 billion bbl of oil, 108.6 Tcf of natural gas, and 1 billion bbl of natural gas liquids (NGLs), while the Haynesville Formation was estimated to contain a mean of 1.1 billion bbl of oil, 195.8 Tcf of natural gas, and 0.9 billion bbl of NGLs. In a report from 2010, the USGS predicted the Bossier held a mean of just 9.0 Tcf of natural gas, while the Haynesville was estimated to contain 61.4 Tcf of natural gas. There has been some confusion regarding the Haynesville and Bossier shales over the years due to the different geological naming conventions in Louisiana and Texas. According to the Texas Railroad Commission, it is generally recognized that the shale interval in east Texas is the Lower Bossier that correlates with the Haynesville of Louisiana. The Upper Bossier Formation is distinguished from the Lower Bossier Formation by its location, to the southwest, and the fact that it is more sand-rich.

Natural Fractures Help Unlock Tight Carbonates in Oman

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211336, “Natural Fractures Help Unlock Tight Carbonates: Redeveloping the Natih B Reservoir in a Giant Field in the Sultanate of Oman,” by Loic Bazalgette, Nawal Aamri, SPE, and Chris Field, Petroleum Development Oman, et al. The paper has not been peer reviewed. _ Within the stratigraphy of one of the largest fields in north Oman is the Natih B reservoir. The development of the reservoir has undergone several challenges over the past decades because of the complexity of the reservoir setting and difficulties in locating the natural fractures. Success in developing such tight carbonates depends on the integration of high-quality seismic, borehole imagery, petrophysics, and dynamic data. The objective of the complete paper is to develop an integrated technical approach that can be used to unlock one of the largest undeveloped resources in the operator’s current portfolio. Introduction With approximately 1 billion bbl of oil originally in place in the development area of interest, Natih B is a significant undeveloped resource in the operator’s portfolio. Attempts were made during the 1980s and 1990s to produce from Natih B, but production was uneconomical because of low productivity or early gas breakthrough. The low matrix permeability of Natih B organic-rich carbonates negatively affected the flow of the early Natih B producers, but the presence of large-scale, vertically persistent fracture corridors and fault-damage zones allowed gas from the Natih A reservoir above to shortcut into these wells. The opportunity to redevelop Natih B was initiated in late 2018. The initiative involved a tight collaboration between the operator’s fractured-reservoir specialist and subject-matter experts of the structural geology of fractured reservoirs and of carbonate reservoir geology. Overview of Natih B Properties The Natih carbonate reservoir is composed of multiple units named Natih A, B, C, D, E, F, and G from top to bottom. In the field of interest, these are structured as a fault-bounded, northeast-dipping monocline (Fig. 1). In this structure, the reservoir is shallow. The initial reservoir pressure is 61 bar at 400 m true vertical depth subsea (TVDSS). All reservoir units are in pressure communication through cross-cutting fracture corridors and have a common free water level at approximately 550 m TVDSS. Current production is from all reservoir units with the exception of Natih B. In the outcrops of the Salakh Arch area (north Oman), the Natih B unit is divided into five subunits. Under Natih B reservoir conditions, this subdivision scheme can be simplified to four well-correlatable subunits with relatively small thickness variations (Natih B1 to B4). In the area of interest, the subunit thickness is approximately 15 m for B1, 30 m for B2, 10–15 m for B3, and 15–20 m for B4. Facies show a cyclicity of clean limestone and organic-rich layers, which is more pronounced in the B1 and B2 subunits. Natih B4 isolates the Natih B reservoir unit from the underlying Natih C reservoir. Above the free water level, the porosity of Natih B subunits B1, B2, and B3 ranges generally between 0.15 and 0.30. The permeability of Natih B is low and ranges from 0.2 to 5 md, with an average of approximately 1 md.

BP’s Argos FPU Offers Fresh Lessons for the Future of Deepwater GOM Projects

Tipping the scales at well over 60,000 tons, BP’s Argos platform is a giant among giants in the deepwater US Gulf of Mexico (GOM). Standing 27 stories tall, the platform has a deck the length and width of an American football field and is one of BP’s largest in the region. One-time KBR subsidiary GVA designed the semisubmersible, the centerpiece of the supermajor’s $9 billion Mad Dog II project built to unlock additional production potential of the Miocene-aged reservoirs estimated to hold more than 5 billion bbl of oil in place. But that wasn’t always the plan. Over a decade ago, BP’s Mad Dog II looked quite different. On paper, the producer was looking at an all-subsea development tied back to another large spar platform—dubbed Big Dog—to host the additional reserves. The development plan envisioned a massive truss spar. Its topsides would need to be installed via three separate offshore lifts then fully integrated at the field site. Any offshore heavy lift is an execution risk. In 1998, an accident while lifting the south module onto Texaco’s Petronius compliant tower in the GOM resulted in the loss of that section of the topsides and delayed the project for a year and a half. That module weighed 3,600 tons. Another hesitation for BP? The price tag. All-in, the spar-based Mad Dog II solution was estimated to cost around $19 billion. That included 30-plus wells. Ultimately, the spar concept was scrapped, and BP moved back to square one and a blank sheet of paper. “The reserves were there,” said Chris Ruthven, project general manager, Mad Dog II. “We knew the reserves were there. In fact, ironically, the team developed the field with the smallest of the four big platforms that BP did back at that point in time: Thunder Horse, Holstein, Atlantis, and Mad Dog. It was the smallest, but ultimately, it was the second-biggest field. It turned out to be huge. All that appraisal showed we’ve got a lot of reserves. So, we went back and went with an analog to Atlantis. Atlantis was seen as a good fit requiring much less offshore integration work. Operations loved the asset, and it was a very safe design. We landed on that concept, and we tried to keep it almost pretty much the same in terms of the overall layout of the facility, but it’s a little bit bigger footprint.” Mad Dog proper was discovered in 1998 via an exploration well in over 6,100 ft of water located in Green Canyon Block 826. The well was drilled to a measured depth of 22,410 ft and encountered around 215 ft of hydrocarbon-bearing Miocene reservoirs. The discovery was followed by a 1999 well drilled to a total depth of 22,410 ft and a further successful appraisal well in February 2000. Mad Dog, covering Green Canyon blocks 825, 826, and 782, was sanctioned as a spar-based development in 2002. The project came online in early 2005.

Sweet spot areas for shale oil and shale gas plays in the Upper Cretaceous rocks of the Middle Magdalena Valley, Colombia: insights from basin modeling

The Middle Magdalena Valley Basin (MMVB) in Colombia has a long history of conventional hydrocarbon exploration and production, with a cumulative production of 2.75 billion barrels of oil as of December 2021. Recent interest has been directed towards unconventional hydrocarbon plays within the basin due to the fine-grained nature of its Cretaceous source rocks and their mineralogy and mechanical properties. This study presents a three-dimensional basin model for three Upper Cretaceous source rocks, known as the “La Luna Formation,” within the MMVB. The model was developed using new data from five outcrops, 7,640 km of 2D seismic lines, and forty-one boreholes, as well as additional data sets such as X-ray diffraction analyses, pyrolysis analyses, well-log correlations, facies analysis, fracture pattern prediction, pore pressure analysis, heat flow estimations, and petrophysical data. The model estimates total retained oil and gas volumes to be 7.95 billion barrels and 4.21 trillion cubic feet in most probable scenarios, after a 15% recovery factor. Seismic interpretation reveals pre-Eocene structures beneath Paleogene and Neogene sediments, and the thickness variation of the source rocks from south to north of the basin. Petrophysical modeling shows effective porosities ranging from 2%–12% and organic porosities lower than 0.1%, with parts of the succession that might correspond to a carrier bed play. From a geomechanical perspective, we identified several brittle strata based on the higher concentrations of carbonates and quartz, and the areas with a higher probability of occurrence of natural fractures. Pore pressure analysis of multiple wells shows that wells in which the Middle Eocene unconformity has beveled the source rocks have no sealing capacity, becoming a risk for the play. The results suggest potential for unconventional hydrocarbon plays in the MMVB, with sweet spot areas being primarily controlled by porosity, thermal maturity, gas-oil ratios, and retained oil and gas volumes, as well as to a lesser degree, the probability of natural fractures and pore pressure conditions. However, further exploration is needed to constrain uncertainties regarding facies and source rock quality, particularly within the depocenters of the basin, in order to prove the economic feasibility of these unconventional plays.

Seismic attribute and well-log analysis for channel characterization in the upper San Andres and Grayburg formations of the Midland Basin, Texas

The Permian Basin is one of the most prolific, and currently one of the most active, oil and gas basins in the USA. The Lower Permian strata in the Permian Basin have produced more than 14 billion barrels of oil (BBO), making it the largest volume of hydrocarbon in the basin. Sedimentation in the Midland Basin during late Leonardian through early Guadalupian (ca. 272–269 Ma) resulted in progradation of shelf edge and ultimately closure of the basin by Middle Permian time. We analyzed a merged seismic survey covering parts of the Permian Basin (i.e., Central Basin Platform and Midland Basin) in Andrews, Ector, and Midland Counties, Texas. The seismic survey and well logs show the presence of gently dipping (ca. 1°) clinoforms in the Upper San Andres and Grayburg Formations on the eastern edge of the Central Basin Platform and western Midland Basin. The seismic attributes, curvature, and spectral decomposition identify low sinuosity slope channels oriented north-south, but such channels do not appear beyond the slope. The shelf edge shifts from north to south during deposition of the Upper San Andres and Grayburg Formations. We identify five basinward shifts noted by the migration of the shelf edge toward the basin center and the presence of channel features along the depositional slope. The petrophysical analysis indicates that channels cut into carbonate rocks and are filled by siliciclastic sediments; this interpretation is supported by the most negative curvature anomalies along the channel axes caused by the differential compaction between the carbonate and siliciclastic rocks. There are a few channels with a northwest-southeast strike, which matches the direction of the Concho Lineament observed by satellite data. Such observations are consistent with previous interpretations of the northern Midland Basin closure during Middle-Late Permian time.

Heating Up in Icy Waters

It was an area once thought to be the last untapped jewel in the hunt for hydrocarbons in the Great White North—a frontier of equal parts promise and peril. The lure of massive oil deposits lurking miles below its icy waters had operators taking a hard look at offshore Eastern Canada as far back as the late 1960s; however initial production from the area—Cohasset-Panuke off Nova Scotia—did not begin until 1992. Logistical challenges related to the remote area and the lack of existing infrastructure made bringing on new production in the region an expensive proposition. The discovered fields would need to be sizable to warrant the required investment. After decades of fits and starts, offshore Eastern Canada has yielded just a handful of major developments, with the best of those facing their own sets of challenges. Newfoundland and Labrador’s Terra Nova, the first development in North America to use floating production, storage, and offloading (FPSO) technology in a harsh-weather environment featuring sea ice and icebergs, came on line in 2002, but has been suspended for the past 3 years due to issues with the vessel. White Rose, another FPSO-based development, came on stream in late 2005 via subsea wells tied back to the SeaRose vessel. After successful completion of one expansion project in the 2010s, a further expansion—West White Rose—was planned but halted in 2020 due to unfavorable oil markets caused by the COVID-19 pandemic. The project envisaged a wellhead platform supported by a concrete gravity structure (CGS) and topsides. The platform will produce back to the SeaRose FPSO. Cenovus approved the restart of the project in May 2022. The West White Rose project is expected to increase the production life of the field by 14 years. Newfoundland and Labrador’s landmark oil production platform Hibernia became the first to produce oil in the province just over 25 years ago. As of August 2022, the project has produced more than 1.2 billion bbl of oil from the field, with almost 580 million bbl remaining proven and possible reserves. The region’s newest producer is the ExxonMobil-operated Hebron. First oil from the field was produced in November 2017—37 years after the field’s discovery by former operator Chevron. Plans to develop the field were shelved in the early 2000s only to be revived later in the decade. As a result of production interruptions and project delays, overall production trends in the region have been on the decline since the end of 2019 (Fig. 1). Off Nova Scotia, both ExxonMobil’s Sable Offshore Energy Project and Ovintiv’s (formerly Encana) Deep Panuke produced commercially for a combined 24 years (19 and 5, respectively) before each was abandoned and decommissioned in 2018. However, the outlook for offshore Eastern Canada today is somewhat brighter.

Lessons Learned from a Prematurely Ended High-Pressure Air Injection Test in a Light Oil Naturally Fractured Reservoir

Summary Sixty billion barrels of oil still reside in the matrix of mature onshore and offshore Mexican reservoirs located in the southeast basins after primary and secondary recovery. Capillary and viscous forces are responsible for this amount of oil retained within the pore structure of the matrix (immobile oil). Gravitational forces are not enough to counterattack these forces due to the high fracturing intensity. On the other hand, laboratory testing demonstrates that oil residing in the matrix could be mobilized by the exothermic reaction that takes place with air injection. Air injection in homogeneous heavy and light oil sandstones and nonfractured limestones, at small or large scales during short and long periods of time, is feasible for producing resources technically and economically nonrecoverable by other means. However, to the best of our knowledge, the published literature does not report any application of an air injection project in naturally fractured reservoirs. During 2015, an air injection pilot test was performed in a light oil naturally fractured reservoir in Mexico, referred to as “A” field. The implementation of the pilot test was preceded by its corresponding laboratory study, which consisted of five accelerating rate calorimeter (ARC) tests and two combustion tube (CT) experiments. The analysis of the aforementioned experimental work led us to corroborate that air and oil react at reservoir conditions. Based on the above finding, the pilot test was conducted by injecting air at a rate of 10 MMscf/D with a wellhead pressure of 4,500 psia for 1.5 years, which was followed by a 1.5-year production period giving a total of 3 years for the pilot test. The results indicate that combustion was successfully applied in the reservoir. However, no oil was produced. This paper discusses the results of a prematurely ended air injection pilot test in “A” field and the main lessons learned from it, which could help in the design and its subsequent implementation in other naturally fractured reservoirs.

E&P Notes (September 2022)

E&P Notes (September 2022)

The history of Madison Group exploration and production in the North Dakota Williston Basin with an update on Madison Group source rocks

The Williston Basin has proven to be a global super basin in terms of oil production and reserves (Sonnenberg, 2020). Although recent production in the basin has been dominated by the Middle Member of the Bakken Formation, the Madison Group has yielded over a billion barrels of oil since 1951. The Madison Group consists of the Charles, Mission Canyon, and Lodgepole formations with various members in each. These formations are found in both the United States and Canada and led Williston Basin production until 2008. As with many petroleum plays, the Williston Basin enticed oil men for many decades with the prospect of oil before finally yielding to success. Success, which is so often accompanied by a bit of good fortune, is a matter of finances, persistence, and technology, ultimately paving the way to successful commercial wells. Many factors contributed to the ongoing production results in the basin and include seismic, horizontal drilling, and completion technologies, and of course, good geological assessments. The history of production in the basin is also detailed by the history of petroleum geochemistry. Source rock and oil geochemistry progressed from scratch tests, test tube pyrolysis, and standard physicochemical properties, such as API gravity, to detailed chemical investigations including high resolution gas chromatography and biomarker analysis.

Caloric Value of Biomass based Power Plants, Life Cycle Assessment and Techno Economic of Different Crops for M.P. (India)

<p>Solar radiation incident on green plant and other photo synthesis organism performs two basic functions such as temperature control for chemical reaction to proceed and the process of photosynthesis. The fundamental conversion process in green plant is photosynthesis which is process of combining CO<sub>2</sub> from the atmosphere with water and light energy to produce oxygen and carbohydrates<sup>1</sup>.</p><p> X [CO<sub>2</sub>] + Y [H<sub>2</sub>O] + light energy photosynthesis X[O<sub>2</sub>] + Y [Cx H<sub>2</sub>O]</p><p> Y [Cx H<sub>2</sub>O] is used to indicate the carbohydrates.</p><p>The world population has increased at an explosive rate from 1.65 billion to just over 6 billion in the 20<sup>th</sup> century, and continues to increase. In the same century, mankind has consumed over 875 billion barrels of oil and it is very likely that even more oil will be consumed in the present century. Annual energy use in developing countries has risen from 55 to 212 kg oil equivalent over the last thirty years, while developed countries use as much as 650 kg oil equivalent per person. In his synopsis ‘Trilemma’ Three major problems threatening world survival’, foresees a three-fold challenge in the 21st century: how can we achieve economic growth, supply food and energy resources, while conserving the environment? To overcome the Trilemma, developing and introducing more efficient energy conversion technologies is therefore important, for fossil fuels as well as renewable fuels. This thesis addresses the question how biomass may be used more efficiently and economically than it is being used today. Wider use of biomass, a clean, renewable and CO<sub>2</sub> neutral feedstock may extend the lifetime of our fossil fuels resources and alleviate global warming problems. Another advantage of using of biomass as a source of energy is to make developed countries less interdependent on oil- exporting countries, and thereby reduce political tension. Furthermore, the economies of agricultural regions growing energy crops benefit as new jobs are created<sup>1</sup>. Biomass primary energy sources: Past, present and future in particular wood, has historically been an important energy source for fires, ovens and stoves. During the Industrial Revolution, coal displaced biomass because of its high energy content and because it is available in large quantities at low cost. At the beginning of the 20th century, oil supplied only 4 % of the world’s energy. Decades later it became the most important energy source. Especially developed countries are highly dependent on oil, which supplies about 96 % of their transportation energy. With world energy demand projected to rise by about 40 % from now to 2020, photosynthesis. Rajiv Gandhi Proudyogiki Vishwvidhalaya implemented the National Policy for Management of Crop Residues to protect the parali (crop residue). On December 10, 2015, the National Green Tribunal (NGT) had banned crop residue burning in the states of Rajasthan, Uttar Pradesh, Haryana and Punjab. Burning crop residue is a crime under Section 188 of the IPC and under the Air and Pollution Control Act of 1981. The Delhi high court had also ordered against burning residues, while Punjab government imposed a penalty of Rs 73.2 lakh farmers in 2016 for burning of crop residue<sup>3</sup>.</p>

E&P Notes (April 2022)

E&P Notes (April 2022)

Regional opportunities for CO2 capture and storage in Southeast Asia

In this paper, we evaluate opportunities for CO2 capture and storage (CCS) within a study area of radius 1,000 km from Singapore. Results show that stationary CO2 emission from the study area is 391 Mtpa. There is mid CO2 storage resource of 0.5 Gt in oil reservoirs. In addition, CO2 enhanced gas/oil recovery (CO2-EGR/EOR) can recover 1.86 billion barrels of oil. The largest amount of CO2-EOR is found in the Minas oil field (767 MMbbl) in Central Sumatra and the Seligi (119 MMbbl) and Dulang (99 MMbbl) oil fields in the Malay Basin. The mid CO2 storage resource in gas reservoirs is 6.2 Gt. Of particular importance is the Arun gas condensate reservoir in the North Sumatra Basin with 1.3 Gt CO2 storage resource and 101 MMbbl condensate recovery by CO2-EGR. The mid CO2 storage resource in saline aquifers is 379 Gt, accounting for the 98% of total CO2 storage. Furthermore, we propose an ASEAN CCS corridor connecting Singapore with the North Sumatra, Central Sumatra, and Malay basins wherein CO2 captured from Singapore and the host country can be transported to oil and gas reservoirs or saline aquifers within these basins for permanent storage.

Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production from All Vertical Wells in the Permian Basin

We analyze nearly half a million vertical wells completed since the 1930s in the most prolific petroleum province in the U.S., the Permian Basin. We apply a physics-guided, data-driven forecasting approach to estimate the remaining hydrocarbons in these historical wells and the probabilities of well survival. First, we cluster the production data set into 192 spatiotemporal well cohorts based on 4 reservoir ages, 6 sub-plays, and 8 completion date intervals. Second, for each cohort, we apply the Generalized Extreme Value (GEV) statistics to each year of oil production from every well in this cohort, obtaining historical well prototypes. Third, we derive a novel physical scaling that extends these well prototypes for several more decades. Fourth, we calculate the probabilities of well survival and observe that a vertical well in the Permian can operate for 10–100 years, depending on the sub-play and reservoir to which this well belongs. Fifth, we estimate the total field production of all existing vertical wells in the Permian by replacing historical production from each well with its prototype. We then time-shift and sum up these prototypes together, obtaining 34 billion barrels of oil as estimated ultimate recovery (EUR). Our most notable finding is that the rate of finding big reservoirs in the Permian has been declining drastically and irreversibly since the 1970s. Today, operators need to drill wells that are twice as deep as the 1930s’ wells, yet they produce 4–12 times less.

E&P Notes (January 2022)

E&P Notes (January 2022)

Forecast of Economic Tight Oil and Gas Production in Permian Basin

We adopt a physics-guided, data-driven method to predict the most likely future production from the largest tight oil and gas deposits in North America, the Permian Basin. We first divide the existing 53,708 horizontal hydrofractured wells into 36 spatiotemporal well cohorts based on different reservoir qualities and completion date intervals. For each cohort, we fit the Generalized Extreme Value (GEV) statistics to the annual production and calculate the means to construct historical well prototypes. Using the physical scaling method, we extrapolate these well prototypes for several more decades. Our hybrid, physico-statistical prototypes are robust enough to history-match the entire production of the Permian mudstone formations. Next, we calculate the infill potential of each sub-region of the Permian and schedule the likely future drilling programs. To evaluate the profitability of each infill scenario, we conduct a robust economic analysis. We estimate that the Permian tight reservoirs contain 54–62 billion bbl of oil and 246–285 trillion scf of natural gas. With time, Permian is poised to be not only the most important tight oil producer in the U.S., but also the most important tight gas producer, surpassing the giant Marcellus shale play.

Simulation of catalytic upgrading in CAPRI, an add-on process to novel in-situ combustion, THAI

Based on the analysis of recent projections by the International Energy Agency (IEA), to meet the growing and subsequently declining demands of oil from now to 2040, we need up to around 770 billion barrels of oil. Since the worldwide total proved reserves of easy-and-cheaper-to-produce conventional oils is roughly only 520.2 billion barrels, the remaining 249.8 billion barrels must be obtained from unconventional petroleum resources (i.e. heavy oils and bitumen). These resources are however very difficult and costly to upgrade and produce due to their inherently high asphaltene contents which are reflected in their very high viscosities and large densities. However, still they should prove attractive development prospects if, as much as practicably possible, their upgrading can be performed in conjunction with in situ or downhole catalytic upgrading processes. Such projects will contribute significantly towards smoother and greener transition to full decarbonisation. Advanced technologies, such as the toe-to-heel air injection coupled to its add-on in situ catalytic process (i.e. THAI-CAPRI processes), have the potential to develop these reserves, but require further developmental understanding to realise their full capability. In this work, a new detailed procedure for numerically simulating the THAI-CAPRI processes is presented. The numerical model is made-up of Athabasca-type bitumen and it has a horizontal producer (HP) well that is surrounded by an annular layer of alumina-supported cobalt-oxide-molybdenum-oxide (CoMo/γ-Al2O3) catalyst. The simulation is performed using the computer modelling group (CMG) reservoir simulator, STARS. This new work has shown that the choice of the frequency factor of the catalytic reactions allowed model validation based on the degree of catalytic upgrading in form of API gravity. Overall, the work herein identifies the important parameters, such as API gravity, peak temperature, oil production rate, cumulative oil production, produced oxygen concentration, temperature distribution profile, extent of coke deposition on the catalyst surface, etc., governing the successful operation of the THAI-CAPRI processes. In particular, this study has shown that even in the vicinities of the mobile oil zone (MOZ) where the catalytic upgrading is expected to be taking place, the catalyst surfaces are covered with high concentration of coke. This finding is in parallel to the observations reported from experiment of CAPRI process alone. Therefore, it is concluded that when experimental studies of the THAI-CAPRI processes are to be conducted, a catalyst regeneration mechanism must be put in place in order to prolong the effectiveness and thus the life of the catalyst so that proper field operation design can be made. Additionally, the study has also shown that the temperature of the MOZ is less than 306 °C and that implies that an external source of heating the annular catalyst layer must be provided in order to effect the catalytic upgrading in the THAI-CAPRI processes. Thus, a new study should look at the feasibility of targeted heating (in the case of microwave) or conductive or resistive heating (in the case of electrical heating) to raise the temperature of the annular catalyst layer to that required to achieve the catalytic upgrading.

Detailed investigations of the influence of catalyst packing porosity on the performance of THAI-CAPRI process for in situ catalytic upgrading of heavy oil and bitumen

Heavy oils and bitumen are indispensable resources for a turbulent-free transition to a decarbonized global energy and economic system. This is because according to the analysis of the International Energy Agency’s 2020 estimates, the world requires up to 770 billion barrels of oil from now to year 2040. However, BP’s 2020 statistical review of world energy has shown that the global total reserves of the cheap-to-produce conventional oil are roughly only 520.2 billion barrels. This implies that the huge reserves of the practically unexploited difficult-and-costly-to-upgrade-and-produce heavy oils and bitumen must be immediately developed using advanced upgrading and extraction technologies which have greener credentials. Furthermore, in accordance with climate change mitigation strategies and to efficiently develop the heavy oils and bitumen resources, producers would like to maximize their upgrading within the reservoirs by using energy-efficient and environmentally friendly technologies such as the yet-to-be-fully-understood THAI-CAPRI process. The THAI-CAPRI process uses in situ combustion and in situ catalytic reactions to produce high-quality oil from heavy oils and bitumen reservoirs. However, prolonging catalyst life and effectiveness and maximizing catalytic reactions are a major challenge in the THAI-CAPRI process. Therefore, in this work, the first ever-detailed investigations of the effects of alumina-supported cobalt oxide–molybdenum oxide (CoMo/γ-Al2O3) catalyst packing porosity on the performance of the THAI-CAPRI process are performed through numerical simulations using CMG STARS. The key findings in this study include: the larger the catalyst packing porosity, the higher the accessible surface area for the mobilized oil to reach the inner coke-uncoated catalysts and thus the higher the API gravity and quality of the produced oil, which clearly indicated that sulphur and nitrogen heteroatoms were catalytically removed and replaced with hydrogen. Over the 290 min of combustion period, slightly more oil (i.e. an additional 0.43% oil originally in place (OOIP)) is recovered in the model which has the higher catalyst packing porosity. In other words, there is a cumulative oil production of 2330 cm3 when the catalyst packing porosity is 56% versus a cumulative oil production of 2300 cm3 in the model whose catalyst packing porosity is 45%. The larger the catalyst packing porosity, the lower the mass and thus cost of the catalyst required per m3 of annular space around the horizontal producer well. The peak temperature and the very small amount of produced oxygen are only marginally affected by the catalyst packing porosity, thereby implying that the extents of the combustion and thermal cracking reactions are respectively the same in both models. Thus, the higher upgrading achieved in the model whose catalyst packing porosity is 56% is purely due to the fact that the extent of the catalytic reactions in the model is larger than those in the model whose catalyst packing porosity is 45%.

Effect of operating pressure on the performance of THAI-CAPRI in situ combustion and in situ catalytic process for simultaneous thermal and catalytic upgrading of heavy oils and bitumen

According to the analysis of the 2020 estimates of the International Energy Agency (2020), the world will require up to 770 billion barrels of oil from now to 2040. However, based on the British Petroleum (BP) statistical review of world energy 2020, the world-wide total reserve of the conventional light oil is only 520.2 billion barrels as at the end of 2019. That implies that the remaining 249.8 billion barrels of oil urgently needed to ensure a smooth transition to a decarbonised global energy and economic systems is provided must come from unconventional oils (i.e. heavy oils and bitumen) reserves. But heavy oils and bitumen are very difficult to produce and the current commercial production technologies have poor efficiency and release large quantities of greenhouse gases. Therefore, these resources should ideally be upgraded and produced using technologies that have greener credentials. This is where the energy-efficient, environmentally friendly, and self-sustaining THAI-CAPRI coupled in situ combustion and in situ catalytic upgrading process comes in. However, the novel THAI-CAPRI process is trialled only once at field and it has not gained wide recognition due to poor understanding of the optimal design parameters and procedures. Hence, this work reports the first ever results of investigations of the effect of operating pressure on the performance of the THAI-CAPRI process. Two experimental scale numerical models of the process based on Athabasca tar sand properties were run at pressures of 8000 kPa and 500 kPa respectively using CMG STARS. This study has shown that the higher the operating pressure, the larger the API gravity and the higher the cumulative volume of high-quality oil is produced (i.e. a 2300 cm3 of ≈24 oAPI oil produced at 8000 kPa versus the 2050 cm3 of ≈17.5 oAPI oil produced at 500 kPa). The study has further shown that despite presence of annular catalyst layer, the THAI-CAPRI process operates stably. However, it is found that a more stable and safer operation of the process can only be achieved at optimal pressure that should lie between 500 kPa and 8000 kPa, especially since at the lower pressure, should the process time be extended, it will not take long before oxygen breakthrough takes place. The simulations have shown in details that at higher pressures, the catalyst bed is easily and rapidly coked and thus the catalyst life will be very short especially during actual field reservoir operations. Since the oil drainage flux into the HP well at field-scale is different from that at laboratory-scale, and at field-scale, the combustion front does not propagate inside the HP well, it will be practically very challenging to regenerate or replace the coke-deactivated annular catalyst layer in actual reservoir operations. Therefore, it is concluded that during field operation designs, an optimum pressure must be selected such that a balance is obtained between the combustion front stability and the degree of catalytic upgrading, and between the catalyst life and its effectiveness.

Can we live within environmental limits and still reduce poverty? Degrowth or decoupling?

Can we live within environmental limits and still reduce poverty? Degrowth or decoupling?

Improving heavy oil production rates in THAI process using wells configured in a staggered line drive (SLD) instead of in a direct line drive (DLD) configuration: detailed simulation investigations

As governments around the world prepare for a transition period to a decarbonised energy and economic future, petroleum is needed to smoothen that transition. Based on the analysis of the International Energy Agency’s 2020 projections, around 770 billion barrels of oil are required to meet demand from now to 2040. However, according to British Petroleum’s Statistical Review of World Energy 2020, as at the end of 2019, the global total reserves of recoverable conventional and unconventional oils is approximately 1734 billion barrels. Out of that, the conventional easy-to-produce light oil accounts for only 30% (i.e. accounts for only 520.2 billion barrels). Therefore, the remaining 249.8 billion barrels of oil needed to satisfy demand up to 2040 must come from unconventional oils, namely heavy oils and bitumen. However, these unconventional resources are very difficult to produce and the current production methods have very high environmental footprints. Consequently, in accordance with climate crisis mitigations, the vast reserves of the virtually unexploited heavy oils and bitumen must be developed using advanced and greener extraction technologies, such as the yet-to-be-fully-understood THAI process which provides partial upgrading of heavy oil/bitumen via in situ combustion. Using validated numerical models which are developed using the CMG’s reservoir thermal simulator, the STARS, which is also used in this study, field scale reservoir simulations of the THAI process were performed with the wells arranged in staggered line drive (SLD) and direct line drive (DLD). Over the 834 days of operating time, the cumulative oil recovery in SLD is 32% of oil originally in place (OOIP) which is equivalent to 26,100 m3 whilst that in DLD is 27% OOIP. This shows that more oil (i.e. an additional 5% OOIP) was cumulatively recovered in SLD compared to in DLD model. It is found that smaller reservoir volume was swept by the combustion front in DLD and thus making the heat-affected reservoir volume smaller than that in SLD model. Furthermore, in DLD, due to the nearness of the injector well to the toe of the horizontal producer (HP) well, oxygen production began much earlier, compared to in the SLD. It is also found that the temperature of the mobile oil zone is higher in the SLD model compared to that in the DLD model. This implies that higher quality oil is produced when the wells are configured in the SLD pattern. Therefore, this first-of-a-kind work has shown that SLD arrangement is far more efficient, safer, and produces higher quality oil than DLD pattern and that actual process engineering designs should use SLD wells configuration.