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Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Three post-doctoral fellows at the University of Alberta, (from left) Sara Eghbali, Ali Habibi, Mahmood Reza Yassin, investigate the impact of shut-in time and flowback strategies on enhanced oil recovery methods. You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers. To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT Apache found something positive to say about its huge gas-producing play in the Permian at a time when gas is selling at rock-bottom prices. When it shut in a 14-well pad on its Alpine High play for 60 days, gas and condensate production surged. It was a rare test of whether a production break can allow water in rock near the fracture face to soak in deeper, allowing gas and liquids to flow more freely.
Li, Qingyun (SLAC National Accelerator Laboratory / Stanford University) | Jew, Adam (SLAC National Accelerator Laboratory) | Cercone, David (National Energy Technology Laboratory) | Bargar, John (SLAC National Accelerator Laboratory) | Brown, Gordon E. (SLAC National Accelerator Laboratory / Stanford University) | Maher, Katherine (Stanford University)
Laboratory experiments have shown that hydraulic fracturing fluids (HFF) can chemically interact with iron(Fe)-bearing minerals in shale, releasing Fe(II) which is then oxidized to form Fe(III)-(hydr)oxide scale. The Fe(III)-(hydr)oxide scale can occlude pore space and reduce oil and gas production in wells. Our previous experimental studies show that Fe(III)-(hydr)oxides can precipitate even under acidic conditions where Fe(II) oxidation is unexpected. This is due to bitumen that is extracted from shale by chemical additives in HFF, which can aid in Fe(II) oxidation and lead to the precipitation of Fe(III)-(hydr)oxides. In this numerical modeling study, we built two geochemical models to simulate our experimental observations. One model was developed to construct the rate law of Fe(II) oxidation in the presence of bitumen in a shale-free system, while the other model was used to understand the chemical reaction network and quantify the impact of bitumen on iron oxidation/precipitation during shale-HFF interactions. Our modeling results have shown that in both high- and low-carbonate shale systems, the presence of bitumen can increase the rate of iron oxidation/precipitation by more than an order of magnitude compared to bitumen-free systems. In addition, the availability of dissolved oxygen to pyrite grains is critical for Fe dynamics during shale-HFF interactions. The chemical reaction network obtained from this study, along with the bitumen-aided Fe(II) oxidation rate law, pave the way for future modeling studies on chemical reactions during hydraulic fracturing and their influence on formation damage and lost hydrocarbon production.
Scale formation during unconventional stimulation can reduce porosity and permeability which, in turn, can affect hydrocarbon flow in oil and gas wells. Operators add iron (Fe) control agents such as citrate and methanol to the hydraulic fracturing fluid (HFF) to prevent the deposition of Fe(III)-(hydr)oxide (Fe(OH)3) minerals in the pore space of shale (FracFocus). Our previous studies have shown that even with Fe control agents, Fe(OH)3 can still precipitate (Harrison et al. 2017, Jew et al. 2017). The Fe in these Fe(III)-bearing precipitates comes primarily from dissolution of pyrite (FeS2), a common mineral in shale, during shale-HFF interactions. In unconventional reservoirs, Fe is released from corrosion of downhole steel in addition to dissolution of native pyrite due to injection of a 15% hydrochloric acid spearhead, resulting in more severe scaling. During pyrite dissolution and pipe corrosion, Fe is released to fluid in the Fe(II) oxidation state, and is further oxidized by dissolved oxygen (O2) in the fluid to Fe(III), which readily precipitates upon acid neutralization. Our previous studies also found that Fe(II) oxidation can be aided by aqueous bitumen leached from shale by organic compounds in the fracturing fluid (Jew et al. 2017). The effect of bitumen on Fe(II) oxidation is enormous, especially under acidic conditions, where bitumen was found to promote Fe(II) oxidation and Fe(OH)3 precipitation that otherwise would not occur. This phenomenon is important, because in most hydraulic fracturing operations, the acid spearhead is the first chemical injected down the borehole for cleaning purposes. Subsequent injections of slickwater/slurry allow for the acid to be pushed into the stimulated rock volume (SRV). Under the acidic conditions along the fluid flow pathways, the formation of Fe(III)-(hydr)oxide scale depends on not only the dissolved O2 concentration in solution but also bitumen-aided Fe(II) oxidation.
ABSTRACT: Unconventional liquid-rich tight reservoirs, such as the Bakken Formation have an enormous amount of oil-in-place that any effort to improve the recovery factor through an EOR process is worthwhile. Due to the ultra-low pore structure of the Bakken Fm, the pore connectivity and pore networks are different from those in conventional reservoirs and thus the fluids transport in EOR processes behave differently. In a CO2-EOR process, the adsorption and diffusion play major roles from both perspectives of production performance and CO2 storage. In addition, our better understanding of geomechanics and coupling it with transport phenomenon has a significant impact on a successful CO2-EOR application in shale plays. In this study, we investigate the changes in reservoir permeability and porosity under different conditions to better understand the correlations between molecular diffusion/adsorption and the stress/strain changes in a typical huff-n-puff process in the Mountrail County, Williston Basin, ND. The stress state during injection, soak, and production may lead to changes in petrophysical properties, fluid/rock molecular interactions, and fluid transport, which are investigated by coupling the geomechanics and fluid flow through a two-way method. This integrated workflow can assist us to understand the relation between geomechanics and CO2-EOR mechanisms in unconventional liquid-rich shale reservoirs.
Nowadays, unconventional reservoirs are a turning point in the global oil and gas industry since these resources have massive reserves with large potential in contributing to hydrocarbon production and ability to gas storage capacity. Ultra-low permeability (nano to micropore size) and low matrix porosity are the main reservoir parameters that distinguish unconventional liquid-rich shale (LRS) reservoirs from conventional resources. Therefore, the combination of long laterals horizontal well and multistage hydraulic fracturing stimulation is a necessary technique to access the unlocked formations by providing more surface area for hydrocarbon between wellbore in the horizontal wells and extremely low pore size in the rock matrix. In North America, the Bakken Petroleum System (BPS) is the largest shale play that has taken attention and interest in oil production. The BPS consists of four units, Upper Bakken Member, Middle Bakken Member, Lower Bakken Member, and the Three Forks Formation. However, the Middle Member and Three Forks formation are only the productive plays since are naturally fractured. Both nonshale units are characterized by the reservoir porosity between 4 to 8% and permeability in the range of microdarcy (Yu et al., 2014; Jin et al., 2017). Several studies showed that these units contain from medium to a large amount of hydrocarbon saturation. Recent reports by U.S. Geological Survey and Energy and Environmental Research Center (EERC) evaluated theirs proven recoverable oil by 0.16 billion m3 (7.4 billion barrels) and initial oil in place in range of 25.43 billion m3 (160 billion barrels) to more than 143 billion m3 of oil (900 billion barrels) (Flannery and Krause, 2006; Continental Resources Inc, 2014; Sorensen et al., 2016). The Bakken oil is a light oil that its composition consists mainly 40% of C1-C4. Hence, oil production depends on the gas expansion mechanism as a primary depletion stage. Moreover, the oil recovery is believed to be less than 8% due to sharply decline in oil production rate when the natural fractured depleted, while slow to no recharge from the matrix rock, because of its extremely low mobility (Kurtoglu, 2013; Sheng, 2014; Yu et al. 2014). Thus, around 3.8 billion barrels of oil is isolated and unrecovered without using unconventional applications like enhanced oil recovery (EOR) methods.
ABSTRACT: The design of a ground support system must be sufficiently robust to hold, retain, and reinforce the excavations throughout its service life. The operational, geological, and geomechanical properties of the surrounding rockmass are known to impact the short- and long-term behavior of ground support systems, yet these impacts have not been fully quantified. In order to quantitatively assess the influence of various parameters on increased demand on ground support elements, a large database was created that collates historical rock support information: type, installation date, and behavior over time of an entire mine sector (18.5 km of drift). Findings demonstrated that the excavation span, rock quality designation surrounding the excavation, and the excavation orientation relative to the foliation appear to be the critical factors controlling the demand on ground support elements.
Current mining operations are witnessing the gradual depletion of mineral resources close to the surface. This scarcity is pushing mining companies to exploit resources at greater depths. However, safe and profitable operations in deep mines face major technical challenges, for example, the loss of the integrity of the excavation. The ground support system is the last line of defense to prevent this consequence; it must be robust enough to retain, hold, and reinforce mining excavations throughout their service lives. Currently, ground support design relies primarily on empirical charts and site-specific professional judgment.
Whereas several studies have assessed factors influencing increased demand on or damage to ground support elements (e.g., Hedley 1992, Kaiser
ABSTRACT: Evaluating stope performance is important for improving stope stability, production efficiency, and profitability. Underground mines are Operating at greater depths where workers and excavations are exposed to hazards such as seismic events, which are not addressed by standard empirical stope analysis. A stope database was created for 114 primary stopes (2.7–3 km below ground level) mined between November 2013 and August 2018. It considers geometrical, geomechanical, operational, and seismological parameters. To assess stope performance, reconciliation between the mined and the designed stope geometries was performed for the entire stope volume and on a surface-by-surface basis. Common stope performance metrics such as overbreak (OB), underbreak (UB), and equivalent linear overbreak sloughing were measured, as were other metrics like rock and backfill overbreak. Results of the univariate analysis showed the OB for the hangingwall of stope type A and the UB for the east and west walls of stope type B were the critical underperforming parameters. Bivariate analysis showed trends linking OB to Richter scale seismic events, rock quality designation, stand-up time, and spatial distribution. Trends were also found linking UB to planned volume and borehole standoff.
Open stoping is a high-production and low-cost mining method to extract ore. To maximize revenue, stopes must be designed to minimize offset from the planned geometry while maximizing stope volume. Thus, stability and performance analyses are necessary for efficient stope design. These analyses take into account diverse factors such as the designed geometry, geomechanical attributes of the rock mass, operational parameters, and the rock mass response to mining. For deep mines that are seismically active, rock mass response can be quantified using seismic event monitoring. Mine seismicity is associated with the mining process (blasting) and high stress conditions (Brown and Hudyma, 2016). Seismicity represents a major hazard that changes the way we interact with the mining environment and it should be considered in stope stability analysis for deep mining. Existing empirical tools for stope design were not developed to account for seismically-active mines and should be used with great caution in such an environment.
ABSTRACT: This paper describes a case study of early mining at the Kittilä Mine and the recovery of the first sill pillars in the Roura and Suuri orebodies. Mining of the first secondary stopes in Roura led to local instability. Both footwall and hanging wall contacts consisted of tightly jointed rock mass with graphite on undulating surfaces. Recovery of the affected area and monitoring results are presented herein. Different approaches were required for sill pillar recovery given the different geometries of the orebodies, and stopes with variable quality backfill. Backfilled stopes were classified according to observed quality, and the mining sequence was modified based on the results. 40-m high Roura stopes were mined from overcuts developed through backfill; 25-m high Suuri stopes were mostly mined with uppers from the undercut. Only the last stope in the 150-m long Roura sill experienced instability, and one secondary stope in Suuri was deemed unsafe and abandoned. Overall, the sill mining in poor backfill conditions was a success.
The Kittilä Mine, owned and operated by Agnico Eagle Finland, is a gold mine located in Finland, 150 km north of the Arctic Circle at 66° latitude. The mining operation started in 2008 from open pits, which were closed in 2012, at which point production moved fully underground. The mineralization is located within a sub-vertical North-South striking shear zone in the Lapland greenstone belt. Gold is refractory and >95% is located in arsenopyrite and pyrite. The Mine consists of four separate orebodies as shown in Figure 1, Suuri, Roura, Rimpi and Sisar, currently producing 1.8 Mt per annum, increasing to 2 Mt in 2021 and requiring over 20 km of development on a yearly basis during mine expansion.
The current known strike length of the mineralization is 3.5 km and the depth extends to at least 1.4 km. The principal mining method is long hole open stoping with Cemented Paste Fill (CPF), using a transverse primary – secondary sequence and longitudinal mining. During mill shutdowns, Cemented Rock Fill (CRF) is used instead of CPF. The mine is currently operated via ramp access; however, a 1.0-km deep hoisting shaft is currently being built with ore handling infrastructure and a new main level for maintenance and personnel use.
PTTEP to Buy Murphy Oil’s Malaysian Business for $2.1 Billion
Matt Zborowski, Technology Editor
Thailand’s PTT Exploration and Production (PTTEP) is doubling down on Malaysian oil and gas in an effort to broaden its reach in its native South-east Asia.
PTTEP has agreed to acquire Murphy Oil’s Malaysian business for $2.1 billion in an all-cash deal. PTTEP also announced that it was awarded two Malaysian exploration blocks in the Malaysia 2018 bid round.
The assets to be purchased produced 48,000 BOE/D net to Murphy last year, of which 62% were liquids, and consisted of proved reserves of 468 Bcf of natural gas and 51 million bbl of liquids. The deal includes five petroleum exploration and production projects—Sabah K, SK309 and SK311, Sabah H, SK314A, and SK405B—in the shallow and deep waters off the Malaysian states of Sarawak and Sabah.
Global Oilfield Services Market Won’t Recover Until 2025
Trent Jacobs, JPT Digital Editor
It has been a tough few years for the world’s oilfield service sector and, according to a new report, the best of times are on hold for a few more.
This is according to Rystad Energy, which says the sector is on pace to capture $920 billion in revenue by 2025. The Norwegian market research firm has highlighted the figure as the high-water mark reached in 2014, a year that ended with crude prices falling by more than 40%.
“This will be the longest slump faced by the oilfield service industry since the 1980s, with about $2.3 trillion in revenues lost along the way,” said Audun Martinsen, Rystad Energy’s head of oilfield service research.
Martinsen continued by noting: “On the bright side, in only 3 years’ time, activity levels will be higher than they were in 2014, although the cost cuts achieved in the sector means spending levels will only be 80% of what was seen in that peak year.”
ExxonMobil, Chevron Target Nearly 2 Million BOE/D in Permian Production
Matt Zborowski, Technology Editor
ExxonMobil and Chevron revealed plans that would result in combined production from the US majors of nearly 2 million BOE/D from the Permian Basin of West Texas and southeastern New Mexico by the mid-2020s.
ExxonMobil revised upward its Permian production outlook by almost 80% to reach 1 million BOE/D by as early as 2024. The operator said its resource base in the basin totals 10 billion BOE.
Chevron expects its output from the basin to rise to 600,000 BOE/D by year-end 2020 before hitting 900,000 BOE/D by yearend 2023. The company said it has added some 7 billion BOE in Permian resources over the last 2 years.
Shale Pioneer: Hard Ceiling On Production Growth Coming
Trent Jacobs, JPT Digital Editor
The central debate today in the US shale business is how long productivity growth will continue. According to one of the most influential voices in the sector, the answer is not much longer.
“I am not particularly optimistic that, over the next 5 years, the industry is going to be able to show the year-over-year improvements in well recoveries that we’ve seen over the past 10 years,” said Mark Papa, chief executive officer of private-equity-backed shale producer Centennial Development Resources.
Papa said the two biggest factors at play are frac hits, or parent-child well interference, and a shrinking inventory of high-quality drilling locations.
Shale CEO on Parent-Child Challenge, Well Declines: We Know
Matt Zborowski, Technology Editor
Much has been made recently about the disparities in production between parent and child wells in US shale basins. The increased attention on the issue is part of broader concern among investors about the ability of operators to maintain high levels of output over the next few years.
However, Doug Suttles, Encana president and chief executive officer, assures that shale executives are acutely aware of the parent-child challenge. His company has been “very public about this for 5 years now,” he said before an audience largely consisting of the investor community at CERAWeek by IHS Markit this week in Houston. He ultimately doesn’t think it’s “a big threat” to the shale sector.
ExxonMobil Makes Huge Gas Discovery Offshore Cyprus
ExxonMobil has made what it says is the world’s third-largest natural gas discovery in 2 years off the coast of Cyprus in the eastern Mediterranean Sea. Based on preliminary interpretation of the well data, the discovery could represent an in-place natural gas resource of up to 8 Tcf.
The Glaucus-1 well, located in Eastern Mediterranean Block 10, encountered a gas-bearing reservoir of approximately 436 ft. The well was safely drilled to a depth of 13,780 ft in 6,769 ft of water.
Industry consultants Wood Mackenzie told Reuters news agency that it estimated recoverable resources of Exxon’s field to be 4.55 Tcf. That compares with its 6.4 Tcf estimate for Calypso, found by Italy’s ENI and France’s Total last year.