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Pioneer Natural Resources announced this week new greenhouse-gas (GHG) emissions-reduction targets across its Permian Basin operations. The plan, rolled out in the company’s new sustainability report, calls for a 25% reduction of GHG emissions by 2030 and a 40% reduction in methane emissions by 2030. The Irving, Texas-based shale producer has also committed to flaring less than 1% of its associated gas and aims to eliminate routine flaring by 2030, and possibly as soon as 2025. By 2022, the new flaring limit will apply to the assets Pioneer is acquiring through its purchase of Parsley Energy. Pioneer announced it was buying the smaller Permian player in a deal valued at $4.5 billion in October.
ExxonMobil announced on Monday a capital spending plan that is focused squarely on the company’s highest-potential developments. The company also issued a warning to investors about a major impairment to many of its dry-gas projects. ExxonMobil plans to spend between $16 billion and $19 billion next year and between $20 billion and $25 billion annually up to 2025. These figures represent a considerable reduction from ExxonMobil’s March capital plan that forecast $30 to $35 billion in exploration and development spending. In addition to its marquee developments offshore Guyana and the Permian Basin in Texas and New Mexico, the new capital program will also focus on “targeted exploration” projects in Brazil and the company’s chemicals division, according to a statement from ExxonMobil.
Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname.
Is It Time To Buy Oil Acreage? The Wolfcamp formation in the Midland Basin, which is part of the Permian Basin, has attracted many oil companies because of its stacked potential. Shown here is a structure and thickness map for the formation. A private-equity firm has agreed to put in $900 million to start a company that will buy US oil and gas operations with a focus on finding more oil. The equity investment by Oaktree Capital Management is far below the records set when the industry was looking up, but with acquisitions activity at a crawl, the timing is striking.
Oka, Fabian (Petronas) | Orient, Samuel (Petronas) | Farhan, Suratman (Petronas) | Hazim, Kamarulzaman (Petronas) | Haydn, Brendt Sinanan (Petronas) | Sylvia, Mavis Ak James Berok (Petronas) | Tomaso, Ceccarelli (Schlumberger) | Supakit, Rugsapon (Baker Hughes) | Jennie, Chin Pui Ling (Schlumberger) | Maisara, Arsat (Schlumberger)
Located in the South China Sea, B oil field was first discovered in 1971 and has been in production since 1982; it is located in offshore of Sarawak, Malaysia, with a water depth of approximately 70 metres. The field has an interval of over 7000 ft. of stacked reservoir sands and thin continuous shale layers, making up approximately 165 individual reservoir units with Late Miocene to Early Pliocene in age, with the stratigraphic intervals reservoir section.
With the objective to find a technically and economically viable enhanced oil recovery (EOR) development concept for B oil field, a feasibility study was conducted by taking several EOR strategies into considerations – low-salinity waterflood, chemical EOR, and immiscible water alternating gas (IWAG). By evaluating individual layers of the field, the study concluded with a recommendation to implement EOR via IWAG on EF reservoirs on the basis of value, timeline, and flexibility for future EORs; IWAG would yield the best result from technical and economical point of view, and also with the ability to be implemented as earliest as possible.
The theory behind IWAG implementation in the field is that the gas component of IWAG injection will help to sweep oil that is left along the top of reservoir sands due to poor water-oil mobility ratio and gravity effects, and due to the fact that gas moves quickly in the reservoir, the water component of IWAG injection will come into assistance by controlling gas mobility and maintaining reservoir pressure as more drainage points are introduced into the reservoir. Additionally, water injection provides the control to improve the aquifer's sweep, three-phase hysteresis effects and reduced residual oil (in gas) is expected to improve recovery mobilizing more oil in the reservoir, and gas injection may also assist to drain oil that are trapped in attic accumulations. In B field, IWAG injection involves gas and water injections into wells that are located down-dip of the reservoir.
Out of four IWAG injector wells in the recent B field drilling campaign, one well was selected to be equipped with a Distributed Temperature Sensing (DTS) system after considering the following benefits that the DTS system would provide:
Conformance monitoring specifically for water to qualitatively identify which sand the water is being injected to or any potential internal crossflow Quantitative flow into each reservoir layer derived from warm-back analysis for the short term and hot-slug propagation for the long term instead of running wireline production logging tool (PLT) Hydraulic fracturing profiling to prevent the formation from fracturing unintentionally due to the water hammer effect or cooling of formation with injection water (i.e., thermal fracture); inversely, when zonal fracturing is intentional and required, profiling to gauge effectiveness and fracture spread Real-time injection issues or zonal anomaly identification to eliminate the need to perform well intervention to obtain information which often results in delayed action Injected gas or water fluid front monitoring when combined with existing DTS in producer wells Reduced intervention risks in a highly deviated well that could lead to fish in hole and potential workover
Conformance monitoring specifically for water to qualitatively identify which sand the water is being injected to or any potential internal crossflow
Quantitative flow into each reservoir layer derived from warm-back analysis for the short term and hot-slug propagation for the long term instead of running wireline production logging tool (PLT)
Hydraulic fracturing profiling to prevent the formation from fracturing unintentionally due to the water hammer effect or cooling of formation with injection water (i.e., thermal fracture); inversely, when zonal fracturing is intentional and required, profiling to gauge effectiveness and fracture spread
Real-time injection issues or zonal anomaly identification to eliminate the need to perform well intervention to obtain information which often results in delayed action
Injected gas or water fluid front monitoring when combined with existing DTS in producer wells
Reduced intervention risks in a highly deviated well that could lead to fish in hole and potential workover
Eromanga Basin in central Australia was deposited from early Jurassic to late Cretaceous and has witnessed commercial discoveries in different formation units throughout the basin's spatial distribution. Lately, operators have shifted from vertical to horizontal wells to enhance production outcomes. However, there are still many challenges for achieving and enhancing these benefits with horizontal drilling. These include navigating an undulating reservoir structure whilst staying in the target zone and maintaining appropriate vertical standoff from oil water contact (OWC) to avoid early water breakthrough.
In this paper, the author summarizes the experiences and approaches made in tackling and resolving these challenges, by elaborating on the new methods applied during the recent horizontal drilling campaign. These include new drilling technologies, such as the latest rotary steerable systems and new logging-while-drilling technologies, such as the multilayer bed boundary detection services. The methodology of using this data both while-drilling and post-drilling for critical decision making on both geosteering and completion strategies, is also addressed. The author illustrates an integrated approach that was adopted by incorporating new data into the reservoir model for the purpose of referencing and planning future wells.
Case studies from two of the recent wells are discussed in detail to illustrate the operational workflows and the integrated approach. Landing and geosteering practices are examined separately to demonstrate how to achieve best results and avoid both identified and potential pitfalls. The overall drilling and production performance of the recent ten wells are summarized, as are the results of applying these methods. Finally, the author reveals the new insights that the post-job data integration brought for the field.
This new approach has allowed the operator to drill an increased number of wells than originally planned in the same timeframe. This approach has also allowed for longer wells to be drilled. By comparing the production benefits with the cost of drilling, the author shows the viability of these methods in resolving the challenges of horizontal drilling in this region.
Excessive greenhouse gas emission and natural gas shortage need to be tackled urgently nationally and globally. In this context, Carbon Capture Storage and Utilization (CCUS) has been proposed to: (1) mitigate the global warming by removing carbon from the atmosphere and, at the same time, (2) create value/reduce the cost by utilizing them for production. CO2 Storage with Enhanced Gas Recovery (CS-EGR) is well fit for the purpose of CCUS. This paper analyses the feasibility of CS-EGR in Australia by characterizing reservoir rock and fluid properties from both conventional and unconventional gas reservoirs, and by modelling the process of CO2 injection, gas production, and CO2 storage.
This paper discusses technical aspects of injection and storage of CO2 and the behaviours of CO2 and methane together with enhancement of gas production. Although both conventional and unconventional gas reservoirs are covered, the emphasis is given to the unconventional gas. CO2 is more preferentially adsorbed to shale or coal than CH4, so the injected CO2 will displace CH4 which then can be recovered. It is also miscible with natural gas and is good for re-pressurizing reservoir. However, these processes are highly influenced by many factors, such as reservoir temperature and pressure, total organic content (TOC), porosity, permeability, pore size (distribution), injection operation, mineralogy, fracture, fluids and so on. Numerical simulation is a perfect tool to study how different parameters interact with each other and eventually affect the efficiency of CS-EGR.
The authors undertake geological and petrophysical characterization of target formations in Australia. It is then followed by numerical modelling which takes consideration of reservoir characterization data and interaction between CO2, CH4, H2O and rock. The sensitivity analysis investigates the performance of CS-EGR at different scenarios and identifies the critical factors. It is worthwhile to mention that two gas injection methods, gas flooding, huff'n'puff, (or cyclic gas injection), are studied and compared.
Based on previous studies, this paper moves a step further by: (1) incorporating reservoir characterization data from Australia gas field in numerical modelling and exploring the feasibility of CO2 Storage with Enhanced Gas Recovery in Australia; (2) investigating both unconventional gas reservoirs and conventional reservoirs and makes a comparison between them; (3) comparing two injection methods for all different reservoirs; (4) performing sensitive analysis of multiple parameters identified from analysis and literature. CS-EGR is promising in achieving "net-zero emission" for Australia.
There was always the challenge to match Permeability estimated from logs to Permeability derived from well tests. The main reason for this is the difference in scale, both vertically in the borehole (net contributing sands) as well as radially out into the formation. The well test that takes into consideration many hours of fluid flow into the borehole was always deemed more representative than permeability derived from logs that measures a smaller area and volume. However, this perception should not relegate log-derived permeability to an insignificant parameter within dynamic models. When wells are stimulated prior to well test (e.g. under-balanced perforation or chemical stimulation for clean-up), it is expected that the permeability from the well test be enhanced as seen in Iago-2 and Gorgon-3 wells.
This paper takes core data from wells in the Carnarvon Basin, create log relationships to predict permeability that match these core data, and compare these to wireline formation tester mobility and to well tests. The results are very promising, and the workflow proposed can be applied to any well in the basin. One of the objectives of this paper is to create a workflow that can be replicated easily and to use raw logs that are available across all wells, in order to reduce the uncertainty in the predicted permeability.
The reservoir sands of the Mungaroo formation are easily recognised by the cross over in the neutron-density logs, in both gas zones and water zones. This is the criteria used by operators to obtain formation pressure tests (MDT/RFT) and this is the same criteria used in this paper to define reservoir sands. Only those core data acquired in reservoir sands are used as the "Learning" dataset to predict permeability. Several learning datasets were created, and these were blind tested on other wells that were not part of the learning dataset. The results of these predicted permeabilities were cross plotted against core permeability that have been over-burden corrected and depth shifted to wireline logs. Where the match is not satisfactory, new learning datasets are derived and this step of the workflow is repeated. At the end, there are four groups of learning datasets that are used as the final results.
These four groups of datasets are associated with four sets of equations and these provides a very good match between the predicted log-derived permeabilities and core plug permeabilities. When compared to mobilities from formation pressure testers, the predicted permeabilities are a very good match. These were then compared to well test permeabilities showing an overall good match. This gives confidence that the predicted permeabilities from the four sets of equations are good and can be applied to any new well targeting the Mungaroo Formation in the Carnarvon Basin.
The first rendering of what is to be the world’s largest direct-air-capture-plant in the Permian Basin. The facility is expected to capture up to 1 million metric tons of CO2 annually for enhanced oil recovery operations in Texas. Occidental Petroleum (Oxy) announced this week that it is joining the race to net-zero carbon emissions. The first step will be to eliminate or offset emissions from its own operations by 2040. The more ambitious leap will require the Houston-based company to do the same for all the oil and gas products it sells by 2050.
Chen, Xiuping (Sinopec Northwest Oilfield Branch Petroleum Engineering Technology Research Institute) | Li, Shuanggui (Sinopec Northwest Oilfield Branch Petroleum Engineering Technology Research Institute) | Wang, Shanshan (Baker Hughes) | Gui, Feng (Baker Hughes) | Zhou, Yongsheng (Baker Hughes) | White, Adrian (Baker Hughes)
The Ordovician fractured carbonate reservoir in the Shunbei field is buried ~7300m below ground level and has presented great challenges for the drilling of extra deep, deviated development wells. Borehole instability-related drilling problems including pipe stuck, pack-off, and mud losses have been experienced frequently during drilling, with many wells being sidetracked three or four times before reaching the target. To understand the failure mechanism and optimize the drilling design to mitigate the drilling risk has become crucial for the field development.
As the basis of the investigation, detailed geomechanical modelling was conducted for a selected area with the most representative drilling problems. Laboratory core tests, wireline logs, image data and drilling experiences were used to build geomechanical models characterizing the in situ stress, pore pressure and rock mechanical properties in both the overburden and reservoir sections. Stress-induced borehole failures observed in the image logs were analysed to help diagnose the failure mechanisms together with the cavings recovered from the problematic wells, which provided significant insights into the likely nature of instability problems in the wells.
The geomechanical modelling from a series of wells revealed that the stress magnitudes in the selected area vary based on the structural location. The wells near the major fault system appear to be in a normal faulting stress regime in the Ordovician reservoir, while the wells nearby the secondary fault system are in a strike-slip faulting stress regime. Different stress regimes and horizontal stress anisotropies have resulted in different behaviors during drilling, with breakouts seen in some vertical wells while not in other vertical wells despite using similar mud weights. during drilling. The variable stress conditions plus the highly developed fractures have caused serious borehole collapse in some wells, but reasonably good hole condition in other wells. Wells using higher mud weight are not necessarily the ones having fewer drilling problems. Although the complex lithology, great depth, and unpredictable distribution of intrusive rocks has complicated the drilling problems, a proper definition of suitable mud weight to control borehole collapse and understanding of the natural fractures might play a bigger role in maintaining borehole stability and mitigating drilling risk.
A good understanding of the stress condition and rock mechanical properties appears to be helpful in defining the proper mud weights and optimizing other drilling parameters to help mitigate the complex drilling problems encountered during drilling in the Shunbei field. However, additional work on the fracture distribution and trend of stress change in the field might be required to help investigate the problem further.