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The United Arab Emirates’ (UAE) chief energy regulator has announced that the country holds a substantial volume of newly discovered unconventional resources as it approved a 5-year spending plan for the Abu Dhabi National Oil Company (ADNOC). The Supreme Petroleum Council, which also serves as ADNOC’s board of directors, placed the estimated reserves of unconventional oil within the Emirate of Abu Dhabi at 22 billion bbl, according to a government news release on 22 November. The figure would place the UAE’s tight reservoir potential on par with that of some of the biggest plays in North America. The government also said that an additional 2 billion bbl of reserves was also recently discovered, raising the UAE’s total conventional reserve estimate to 107 billion bbl. Both the conventional and unconventional estimates were independently verified by Houston-based reserves specialist Ryder Scott.
Investments from global exploration and production companies (E&P) in 2021 are projected to reach around $380 billion, almost flat year-on-year, a Rystad Energy report shows. About 20%, or $76 billion, of the estimated 2021 investments could be at risk of deferral or reduction, with the remaining amount being categorized in the safer tiers of low and medium risk. The amount is Rystad’s base-case scenario, but, with 2020’s market turbulence fresh in mind and the currently uncertain rollout timing of the recently announced COVID-19 vaccines, it is worth expanding the forecast to a range of $350 billion to $430 billion, incorporating some scenario deviation. Investments may rebound to the precrisis level of $530 billion by 2023 if oil prices rise to around $65/bbl—though, after the previous market crisis in 2014, annual E&P investments never recovered to the precrisis level of about $880 billion and instead settled at $500 billion to $550 billion. Much of that reduction was because of supply chain and efficiency improvements, leaving little scope for further such reductions this time around.
NextTier Oilfield Solutions announced today that it has recently started field testing electric fracturing pump technology developed by National Oilwell Varco (NOV). The two Houston-based energy companies are looking to the electric-based systems, also known as e-fleets, to improve efficiency and lower emissions at unconventional wellsites in the US. NextTier is currently using prototypes in the field and, if the pilot proves out, then the pressure pumper may end up purchasing the first e-fleet manufactured by NOV, the announcement said. NextTier added that its pending adoption of e-fleets would complement its dual-fuel fracturing fleets that can run on either diesel fuel or cleaner-burning natural gas. Like other commercial e-fleets, NOV’s system relies on gas turbines to generate power that is then used to drive the high-horsepower pumps.
After a year’s worth of hyperactive volatility, the outlook for oil production next year looks positively comatose. Both the big oil-producing countries in OPEC and the US shale producers appear likely to be delivering volumes in between the lows reached during the worst of the COVID-19 demand swoon and last year’s all-time high. With another surge in COVID-19 cases in progress worldwide, OPEC said it would stick with its current quotas because moves to slow the incidence of the infections are likely to stall demand growth, or worse. OPEC+, which includes Russia and other countries from outside the 13-member organization, predicted demand rising to 96.84 million B/D in the monthly report, down 80,000 B/D from its previous outlook, according to Reuters. Oil prices rose after that news but also likely benefitted from optimistic reports from two vaccine developers that said their clinical trial results to date indicate effectiveness.
Propellant enhancement is a method of increasing permeability through the application of a transient high pressure event to the target formation. As distinct from hydraulic fracturing, propellant enhancement does not involve the application of chemicals or water and consequently does not present the potential for legacy environmental issues. This paper compares the regulatory aspects of propellant enhancement within the states of Australia and also the differences between environmental impacts.
A series of propellant enhancements were undertaken for a suite of gas wells in the Surat Basin, Queensland. Propellant charges in the range 18-30 kg were initiated, with deflagration times in the range 500-1,000 milliseconds. The compliance regime for the transport, storage and use of propellant is established under the state’s
There are three categories of fracturing used to increase permeability: explosive fracturing; hydraulic fracturing; and propellant enhancement. Explosive fracturing applies a very high pressure transient over a period of a few microseconds and can cause local, radial fracturing but with less desired compaction; hydraulic fracturing applies a lower pressure but over a longer period and with greater surface power, resulting in fractures that can extend 200-300 m, largely in the vertical plane; and propellant enhancement, which applies a mid-range pressure over a period of 10-1,000 milliseconds, resulting in fractures extending tens of metres but with random distribution. Residuals from the deflagration process are nitrogen, hydrogen chloride, water and carbon dioxide. There are no precursors for the BTEX suite and no conditions arising that could produce BTEX.
A prime question was to determine whether propellant enhancement is captured under the term ‘hydraulic fracturing’ in states’ regulations across Australia. Propellant enhancement is a technology with very few environmental impacts. Vehicular movements to support propellant enhancement are less than five percent of those to undertake hydraulic fracturing on the same formation. There is no requirement for waste water treatment.
As the shale development activity in the Permian continues to be strong and oil prices recover, increasing numbers of infill child wells are being drilled as operators want to improve recovery from each section and continue to meet their production targets. However, production data suggests that both parent and child wells suffer from production losses if they are located too close to one another.
The cube model concept, which is also referred to as supersize fracturing, was first introduced about two years ago and has been piloted in the Permian Basin. In a cube model, multiple wells, usually more than 30 horizontal wells with five to six wells in each different horizontal layer, are drilled and completed in the same section. Operators produce those wells simultaneously with the objective of mitigating the parent-child effect of unconventional reservoirs.
Nevertheless, with all wells producing at the same time and competing for production from the first day, will this benefit ultimate recovery? This question was investigated through comprehensive fracture and reservoir modeling and simulation. A reservoir dataset for the Spraberry Formation in the Permian Basin was used to build a hydraulic fracture and reservoir simulation model.
Different field development strategies were studied. Models representing a traditional parent-child scenario with five parent wells completed and produced one year before four infill child wells and a traditional parent-child scenario with five parent wells completed and produced five years before four infill child wells are compared. In these cases, a geomechanical finite-element model (FEM) was used to quantify the changes to the magnitude and azimuth of the in situ stresses from the various reservoir depletion scenarios. Next, a cube model with nine horizontal wells completed and produced simultaneously was analyzed. These three scenarios were expanded to include 19 horizontal wells with the same methodology.
This study aims to help operators in the Permian Basin, as well as in other unconventional reservoirs to understand how different field development strategies affect ultimate hydrocarbon recovery and net present value.
Formulating a robust and efficient production optimization and forecasting tool for unconventional oil and gas assets is a challenging task. This is mainly due to the high number of wells involved and the limited predictability of detailed individual well performance until there is sufficient production history.
Current methods to optimize and forecast production rely on type curves and surface network models, neither of which account for changes in the wellbore condition. Generally, these activities are conducted separately and are rarely fully integrated.
A solution that can automatically match real-time performance of an unconventional asset well is presented in this paper. The implemented solution replicates performance of unconventional wells using transient models. Input parameters for all models honour a given range of realistic operational conditions and are automatically regressed to match the historical performance. At a specified interval, historical production is updated in the models and regression is performed automatically to keep the multiple models updated.
This solution can address challenges related to historical well allocation given by lack of remote sensing, by coupling the well model to a network model. The use of automated regression tools to identify outliers reduces the requirement for routine engineering review, thus making forecasting for thousands of wells manageable. Having accurate well models coupled with a network model allows automatic allocation matching at separator levels and hence a calibrated network model leading to production optimization and better field management. Consequently, a robust optimization and forecasting tool for unconventional assets is achieved.
Bonanza Creek Energy said this week it is purchasing smaller rival HighPoint Resources in an all-stock deal the companies said is valued at nearly $376 million. The acquisition is expected to put Bonanza Creek on pace to produce 50,000 BOE/D (about 53% oil) from more than 200,000 contiguous acres in Colorado’s DJ Basin. A key driver behind the deal was Bonanza Creek’s need to improve sustainable free cash flow by creating a company with greater scale, said a company announcement. HighPoint meanwhile is entering into the deal under a restructuring plan, signaling that its only other option is to seek court-supervised bankruptcy protection. Bonanza Creek said its cash flow target for next year is $130 million that will be used to reduce debt, pay investors, and development reinvestment.
Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing.
Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant.
The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO2, energized, and foamed fluids (CO2 and N2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable.
This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.
Ness, Knut Johannes (ADNOC Offshore) | Exposito Gonzalez, Juan Jose (ADNOC Offshore) | Iftikhar Choudhry, Bilal (ADNOC Offshore) | Torres Premoli, Javier Ernesto (ADNOC Offshore) | Couzigou, Erwan (ADNOC Offshore)
The abstract must contain conspicuous acknowledgment of SPE copyright.