Forty years since Norway first exported gas to international markets (September 1977, via Norpipe), the country has an ambitious goal. While continuing to export natural gas, it wants to create a "value chain" to capture and emit CO2, potentially even importing the substance from others to store it in vast offshore aquifers. This way, Norway exports its fossil fuel, while taking other's emissions out of the atmosphere. Globally, there are 17 carbon capture and storage (CCS) projects in operation, which capture and store a total 30 million tonnes per year (MTPA) of CO2. In May 2017, there were seven large-scale projects operational, with a combined capacity of 31 MTPA: a further five, with 9 MTPA capacity in total, were under construction, while more than 100 small-scale plants were operating, according to Norway's state-owned CCS firm Gassnova.
For the first time, the general public will have complete access to the subsurface and production data from a field on the Norwegian continental shelf (NCS). Equinor announced that it will disclose the data from Volve, a shallow-water oil field located in the southern part of the Norwegian North Sea approximately 125 miles west of Stavanger. Following its startup in February 2008, Volve's production lasted for approximately 8 years. It was originally scheduled for 3 to 5 years of operation. At its peak, the field produced 56,000 BOPD, and a total of 63 million bbl of oil were produced before the field's shutdown in September 2016.
ExxonMobil’s Eighth Discovery Off Guyana Adds Another Development Possibility
Matt Zborowski, Technology Writer
ExxonMobil said it has “encountered 78 m of high-quality, oil-bearing sandstone reservoir” near the Turbot discovery southeast of the Liza field offshore Guyana.
The supermajor’s eighth discovery in the burgeoning oil province could bring about a new development opportunity in the southeast portion of the 26,800-sq-km Stabroek Block. The first phase of development drilling on Liza field began in May.
The Longtail-1 discovery well was drilled to 5,504 m in 1,940 m of water by the Stena Carron drillship, which spudded the well on 25 May. It is the second discovery in that area after the Turbot discovery of late 2017. The two discoveries’ estimated recoverable resources total more than 500 million BOE, said ExxonMobil.
GE To Spin Off Baker Hughes
Pam Boschee, Senior Editor
GE is spinning off Baker Hughes (BHGE) in its strategic plan for growth and shareholder value creation. It plans to focus on aviation, power, and renewable energy.
GE CEO John Flannery said these areas share technologies, digital and additive strategies, and business models.
The separation from Baker Hughes will take place over the next 2 to 3 years as part of GE’s effort to “make its corporate structure leaner and substantially reduce debt,” the company said in a statement. GE Oil and Gas merged with Baker Hughes in July 2017, with GE holding a 62.5% stake. BHGE’s revenue on an annualized basis is $22 billion.
GE Healthcare will also be separated into a standalone company, which will begin immediately and progress over the next 12 to 18 months. The spinoffs of BHGE and GE Healthcare are part of GE’s efforts announced last fall to sell $20 billion worth of assets.
The Big Unknowns for World’s Balancing Act of Supply and Demand
Trent Jacobs, Digital Editor
Last year was a dynamic one for both oil producers and consumers. For much of 2017, oil prices headed north but consumption still outgrew daily production—even as those totals were rising too.
The net effect was seen as a positive for what has been a chaotic oil market in recent years. However, an annual report from BP’s economic group that studies market forces for the company has raised questions about what could disrupt this tenuous balance going forward.
Driven by rising but still relatively low prices, 2017 saw world oil demand increase by an impressive 1.7 million B/D. This 1.8% increase stands above the 10-year average of 1.2% and marks the third year in a row that these figures have seen an uptick.
Equinor Releases Subsurface and Production Data From NCS Field
Stephen Whitfield, Senior Staff Writer
For the first time, the general public will have complete access to the subsurface and production data from a field on the Norwegian continental shelf (NCS). Equinor announced that it will disclose the data from Volve, a shallow-water oil field located in the southern part of the Norwegian North Sea approximately 125 miles west of Stavanger.
Following its startup in February 2008, Volve’s production lasted for approximately 8 years. It was originally scheduled for 3 to 5 years of operation. At its peak, the field produced 56,000 BOPD, and a total of 63 million bbl of oil were produced before the field’s shutdown in September 2016. Equinor said that one of the goals of the data release is to allow students from relevant fields of study to train on real data sets.
Equinor, ExxonMobil Rack Up More Brazilian Pre-Salt Acreage
Matt Zborowski, Technology Writer
Equinor secured interests in two of three blocks awarded 7 June during Brazil’s 4th pre-salt bid round, further expanding its footprint in the growing offshore province alongside ExxonMobil, Shell, BP, and Chevron.
Three of four blocks were awarded overall, each of which will be operated by Petrobras. The state-owned firm has a right of first refusal to petition the government to operate all pre-salt blocks offered. The round received some $800 million in signing bonuses and $190 million in planned exploration investments.
The Norwegian firm took a stake in the highly coveted Uirapuru block in the Santos Basin with partners ExxonMobil and Petrogal Brasil. Petrobras exercised its right to enter the consortium and will be the operator with a 30% interest. Equinor and Exxon-Mobil will each have a 28% stake, with Petrogal Brasil holding the remaining 14%.
For the first time, the general public will have complete access to the subsurface and production data from a field on the Norwegian continental shelf (NCS). Equinor announced that it will disclose the data from Volve, a shallow-water oil field located in the southern part of the Norwegian North Sea approximately 125 miles west of Stavanger. Following its startup in February 2008, Volve’s production lasted for approximately 8 years. It was originally scheduled for 3 to 5 years of operation. At its peak, the field produced 56,000 BOPD, and a total of 63 million bbl of oil were produced before the field’s shutdown in September 2016.
For the first time, the general public will have complete access to the subsurface and production data from a field on the Norwegian continental shelf (NCS). Equinor announced that it will disclose the data from Volve, a shallow-water oil field located in the southern part of the Norwegian North Sea approximately 125 miles west of Stavanger. Following its startup in February 2008, Volve’s production lasted for approximately 8 years. It was originally scheduled for 3 to 5 years of operation.
Equinor is considering using electrical power from land-based sources instead of gas turbines on several of its North Sea platforms, including Troll C. The move could help the company see significant reduction in its carbon dioxide emissions. Equinor is looking at the possibility of supplying power from land to select offshore facilities in the Norwegian continental shelf (NCS) that are currently being powered by gas turbines. The transition may cut carbon dioxide (CO2) emissions by more than 600,000 tonnes/year if implemented. Troll C and the Sleipner field center, which includes the Gudrun tie-in platform, are the facilities being considered. All three platforms are in field areas that already receive power from land.
Water-alternating-gas (WAG) injection is a technique employed in EOR (Enhanced Oil recovery). WAG injection can be immiscible or immiscible with water and gas being injected into the hydrocarbon liquids reservoir to promote greater recovery. WAG injection is effective as gas typically has greater microscopic sweep efficiency whilst water has better macroscopic sweep efficiency. It is important to be able to characterise and quantify how much the degree and type of small/medium scale heterogeneity during WAG flooding could affect the recovery factor from a reservoir, such that during project evaluation teams are able to properly evaluate the ranges on uncertainty on recovery factors and the economic benefit of the project as well as risks associated with WAG implementation.
The Hutton field is located in the North Viking Graben area of the North Sea and the lithology of the reservoir section is made up of Brent group sandstones which are highly heterogeneous in the horizontal and vertical directions at a small scale (i.e. pore scale and plug scale) and at a medium scale (the vertical layering of different formations).
The effect of reservoir heterogeneity on WAG efficiency has been evaluated using dynamic reservoir simulation models of the Hutton field. Input parameters were based on an available model of the Hutton Field. A fine grid geological model (grid size 5ft × 5ft × ~2ft) has been created of a small section of the Hutton reservoir. A variety of field development schemes were evaluated including depletion, water injection, gas injection and immiscible WAG production scenarios. Geological models were created for three scales of heterogeneity (small scale and medium scale heterogeneity models, and a homogeneous model) based on interpretation of log data from a set of three control wells. Compositional simulation models were used to model the dynamic behaviour. Two phase relative permeability (oil / water and gas / oil) data was used, as three phase relative permeability data for Hutton was not available. There is no hysteresis data available for the Hutton field, therefore separate test runs were carried out to evaluate how hysteresis might affect recovery factor during WAG injection using two and three phase relative permeability data and parameters for use in the Killough correlation for hysteresis.
Immiscible WAG injection is beneficial in reservoirs with small and medium scale heterogeneity and gives ~5% improvement in recovery factor when compared to water injection. However, when hysteresis is included, the recovery factor may be higher than this by another ~10%. WAG injection may provide inferior recovery factors to water injection in homogeneous reservoirs. However, simulations indicated that some limited gas injection into a homogeneous reservoir may prove beneficial for accessing attic oil. It is recommended that laboratory testing of core samples (core flood experiments) be carried out prior to a WAG injection specifically with the aim of identifying the most appropriate hysteresis model and to give good relative permeability data across all three phases.
Sleipner Vest is a large gas-condensate field which is produced by pressure depletion. Currently (January 2018) the best production well is B-1. B-1 is placed in a segment with very strong pressure support from aquifer. In summer 2016, it was about to water out. A straddle operation was planned and executed. The straddle operation was very successful. More than a year later, B-1 still produced more than twice as much as any other Sleipner well. However, the water is eventually expected to come back in the remaining perforations. Concepts for crossflowing the gas and water production from the well into another reservoir has been investigated.
Development of ultra high CO2 field in Malaysia is the next frontier as far as contaminated green field development is concerned. Large hydrocarbon reserve is a major driver to mature technology to support the development of contaminated fields. However, managing the contaminant CO2 is still a major drawback as far as technology is concerned. Base case consideration for CO2 emission mitigation for offshore high CO2 gas fields had always been geological injection even though it deteriorates the overall field economics to a point which may prove to be prohibitive for some field development cases. An alternative method to mitigate CO2 would be the conversion of CO2 to higher value products which provides return in the form of additional revenue or profit. The monetory income from the conversion of CO2 can be utilized to either fully or partly offset the high cost of CO2 injection. This paper attempts to summarise the experience based on feasibility study, technical consideration and lesson learnt by PETRONAS to mitigate the CO2 emissions from the development of such high CO2 gas fields. The summary is done in the context of selecting the suitable CO2 mitigation technology, scale of conversion, maturing the technology and economic consideration as an integral part of the field development.
Danaei, Shahram (Department of Petroleum Geosciences, Universiti Teknologi PETRONAS) | Hermana, Maman (Department of Petroleum Geosciences, Universiti Teknologi PETRONAS) | Ghosh, Deva Prasad (Department of Petroleum Geosciences, Universiti Teknologi PETRONAS)
For many decades, Enhanced Oil Recovery (EOR) scheme has been initiated to improve recovery factor for various oil and gas fields worldwide and Malaysian basins also are no exception. Monitoring reservoir during EOR schemes has become a priority for oil and gas companies operating in Malaysian basins. Monitoring reservoir has an incontrovertible part in reservoir management and field development planning. As a monitoring technique, 4D seismic method has proven its ability to surveil primary production of the oil and gas reservoirs. This technique has also been used to monitor the reservoirs under various phases of enhanced oil recovery schemes.
4D seismic reservoir surveillance provides a sizable coverage over reservoirs which makes it possible to depict reservoir fluids movement. This advantage and also its ability to capture acoustic contrasts between various reservoir fluids have made the 4D seismic as a widespread technique for monitoring purposes. 4D seismic reservoir surveillance has been implemented for a field located in Malaysian basins. The first seismic survey has been shot in 1995 prior to production and injection activities. In 2000, production started from reservoir I-X in the field and water injection scheme also commenced exactly in the same year. Field asset team including geoscientists and engineers faced with early water production for a producer well; therefore, they decided to run another seismic survey in 2006.
Time-lapse seismic data analysis has been performed based on the qualitative interpretation of 4D seismic data. The analysis has been done separately for both seismic surveys and also on seismic differences of monitor minus the baseline. This analysis has been done on amplitude for both seismic surveys and also on 4D amplitude values. In addition, 4D seismic attributes have been used to monitor the reservoir and depict the movement of injected water. 4D Phase shift (−90°), and 4D acoustic inversion complement the injected water monitoring.
The results for various time-lapse seismic attributes are similar which indicate the expansion of injected water from injector wells after six years of aggressive water injection scheme. This expansion seems almost uniform for the five downdip injector wells; however, uneven pattern in water distribution for updip injector well proves the inefficient oil sweep for that region. Remaining oil area has been determined based on the analysis of 4D seismic attributes. The early water breakthrough for a producer well has been contributed to a channel between the well pairs (Injector and producer).