Good Petrophysical Properties Research Articles

E&P Notes (July 2019)

Weatherford Plans Chapter 11 Restructuring Weatherford International is headed to bankruptcy court to try to slash its crushing debt load. The services company said it planned to file under Chapter 11, and announced that its senior creditors are expected to facilitate financing that will sustain operations during bankruptcy and afterward. The company’s statement on the planned filing said its operations are continuing and the bankruptcy process will have “no expected impact on customer, vendors, partners, or employees.” A company spokesman said the move was a “balance sheet restructuring to address the company’s debt burden,” and was not a restructuring of operations or a declaration of bankruptcy. Venezuela Oil Output Sinks to Lowest Level Since Early 2003 Crude oil production in Venezuela declined to its lowest level in more than 16 years in April, and the recent freefall could accelerate further as US sanctions-related deadlines pass. The politically and economically beleaguered country’s crude output averaged just 830,000 B/D in April, its lowest mark since January 2003, according to data from the US Energy Information Administration (EIA). The rate of decline shot up during the first quarter to 135,000 B/D/month, much higher than the 33,000 B/D/month drop observed during 2018. EIA forecasts Venezuela crude output to continue falling through at least year-end 2020. Eni Tallies Fifth Oil Discovery in Angola Deepwater Exploration Campaign Italian multinational firm Eni has made its fifth light-oil discovery on Block 15/06 in the deep waters off Angola through an exploration program it launched just last year. The Agidigbo-1 NFW well proved a single hydrocarbon column consisting of a 60-m gas cap and 100 m of light oil in Lower Miocene sandstones with good petrophysical properties, Eni said. Drilled by Seadrill’s West Gemini sixth-generation ultradeepwater drillship, the well reached TD of 3800 m in 275 m of water. Analysis of the results indicate between 300–400 million bbl of light oil in place, the operator said. ExxonMobil Moves Forward With Second Guyana Development ExxonMobil has made a final investment decision (FID) for the second development phase of the Liza field on the Stabroek Block offshore Guyana. Expected to start up in mid-2022, Liza Phase 2 will produce up to 220,000 B/D of oil. The major is proceeding with the project after receiving government and regulatory approvals. As with Liza Phase 1, the second phase will utilize a floating production, storage, and offloading (FPSO) vessel, which will be named Liza Unity. Six drill centers are planned with a total of 30 wells, including 15 production wells, nine water injection wells, and six gas injection wells. The project is expected to cost $6 billion, including $1.6 billion for the FPSO, and will develop 600 million bbl of oil. UK Continental Shelf: Two Big Discoveries and More to Come The fortunes of the upstream industry on the UK Continental Shelf (UKCS) may be turning. Two big discoveries have been reported over the past 8 months and a gradual upturn in drilling is expected in the near term. First, Total in September announced its Glendronach find west of Shetland. The French operator encountered 42 m of net gas pay in a high-quality Lower Cretaceous reservoir. Recoverable resources are estimated at 175 million BOE. Then, in January, CNOOC said it made the play-opening Glengorm discovery, intersecting about 38 m of net gas and condensate pay in the Central North Sea. Recoverable resources there are estimated at 250 million BOE, which is the largest discovery on the UKCS in a decade. Total is also a partner in Glengorm. Shell Partners with Startup to Get a Better Taste of the Reservoir Wireline formation tests represent an oil and gas company’s first real taste of the reservoir’s prize, but they have a history of capturing nonrepresentative samples. For a solution, Shell is turning to a new software developer called Senslytics to see if it can make wireline formation testing more accurate and predictable. These tests involve sending a probe downhole to contact the exposed rock along the wellbore, then pumping reservoir fluids into the device to analyze their chemical composition. “The problem with this process is that when you’re engaged at such distance down below, you don’t know how long to sit there,” said Rabi Chakraborty, president of Senslytics.

Major structural elements and petrophysical properties of the miocene section, “XYZ Field”, western shallow Offshore Depobelt, Niger Delta

R1, R2, R3, and F. reservoir units were identified in the XYZ Field. The reservoirs are within the Oil proven fault block and F reservoir is located on the footwall structure of the second synthetic fault with similar structural characteristics. The faulting in the XYZ field resulted in a downward movement of the XYZ Discovery relative to the XYZ prospects. The structural development process of the field was a syn-sedimentary. This explains why the XYZ-1 penetration in the footwall of the synthetic found oil-in F sand. However, petrophysical results show that the reservoirs of interests have good petrophysical properties with minimum porosity of 0.1 and maximum water saturation of 0.7. The discoveries by the XYZ-1 well prove the existence of a working hydrocarbon source and charge system. However the distribution pattern of the discovered hydrocarbons is not yet understood. Â

The Sukhana Sedimentary Basin, Siberian Platform: Source Rock Characterization and Direct Evidence of Oil and Gas Presence

Abstract —Despite the known large natural bitumen accumulations and oil seeps in several kimberlite pipes along the periphery of the Sukhana sedimentary basin, interpreted as direct evidence of petroleum potential, the basin still remains one of the least studied (by geological and geophysical methods) regions of the Siberian Platform. The platform cover of the basin is composed by Riphean, Vendian, and Cambrian clastic (terrigenous) and carbonate deposits reaching 5.5–6 km in thickness in the central part of the basin. The hydrogeological specifics of the basin is largely governed by its location within the northern geocryological zone (Olenek cryoartesian basin) and is expressed as a continuous distribution of permafrost aggraded into the permafrost zone of unique thickness. Direct indicators of ore and gas presence are the East Anabar, Central Olenek, and Siligir–Markha fields of natural bitumen and oil shows in kimberlite pipes of the Daldyn–Alakit region (Udachnaya pipe). The bituminous-carbonate sediments of the Khatyspyt Formation (Vendian, Ediacaran) and the highly carbonaceous carbonate–siliceous–shaly sediments of the Kuonamka Formation (lower–middle Cambrian) are the Sukhana source rock complexes. The geochemically substantiated genetic relationship between the natural bitumen deposits of the East Anabar field and the organic matter of the Vendian Khatyspyt Formation makes it possible to estimate the area of the spread of the latter far to the west, beyond the axial part of the basin. Gammacerane, inherited from the organic matter of the Khatyspyt Formation and ranking as well-preserved and most characteristic biomarker of these bitumens, provides a compelling evidence of their consanguinity. The bitumen and oil of kimberlite pipes in the south of the basin, in the area of reefs of the Siligir–Markha bar, are similar in all geochemical criteria to oils of the Nepa–Botuobiya anteclise. In particular, in primary geochemical characteristics (12- and 13-monomethylalkanes, unique secosteranes, identical carbon isotope composition, etc.) the oils of the Udachnaya pipe are identical to the Irelyakh oils (oil field in the Mirnyi arch). No accumulations of oil or natural bitumen genetically related to the highly carbonaceous Kuonamka Formation have been found within the basin. At the same time, “intraformational” shows of viscous oil, solid bitumen, and allochthonous bitumen (bitumen extracted with chloroform) were documented directly in the sections of the formation, which makes the sedimentary basin a very attractive target for “shale oil” exploration. As for the regional assessment of the petroleum potential of the entire basin, its axial part (Sukhana depression) complicated by local uplifts is of the greatest interest. Both the Khatyspyt and Kuonamka Formations are widespread there, with the thermal maturity of their organic matter corresponding to the oil window. In addition, the regional reservoirs at the Vendian–Cambrian boundary have good petrophysical properties on both the western and the eastern flanks of the basin.

New Technologies Maximize Production in Viscous-Oil North Slope Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171896, “The Use of New Technologies To Maximize Oil Production in a Viscous-Oil Field in Arctic Environment: The Nikaitchuq Experience,” by S. Raniolo, SPE, S. Mancini, and S. Vimercati, Eni E&P; and P. Gentil, D. Simeone, SPE, and A. Buchanan, Eni Petroleum, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. Oil quality and drilling-pad constraints for a viscous-oil field defined a development scheme that consisted of a waterflood line drive with horizontal producers and water-injection (WINJ) wells side by side. Different well designs for producer wells were implemented: a single horizontal trajectory undulating between the two sand bodies in counterphase with the related water injectors, a fishbone design with the main borehole in the lower sand and multiple branches in the upper sand, and a multilateral (ML) counterphase design with extended-reach undulating dual laterals. As a result of the ML campaign, well productivity doubled. Introduction The field is located on the North Slope of Alaska in the Beaufort Sea in water depth less than 20 ft. The reservoir consists of four zones hydraulically communicating, named OA1, OA2, OA3, and OA4. The differentiation is mainly sedimentological; OA1 and OA3 are associated with a more-proximal depositional system, while OA2 and OA4 are characterized by a predominance of thin laminated silty sandstones because of a more-distal depositional system. The crude quality and drill-pad constraints (one offshore, one onshore) drove a development concept that consisted of a waterflood line drive with alternating horizontal producers and WINJ wells with a 1,200-ft spacing. The lateral sections are 6,000–10,000 ft long through the reservoir with undulating counterphase trajectories across the two main sand bodies. Challenging very-extended- reach wells with a stepout ratio higher than 6 have been achieved (Fig. 1). The undulating counterphase well trajectories were selected for producers and injectors to guarantee optimal pressure support and avoid early water breakthrough. The original design was based on predrilling assumptions; however, the reservoir was revealed to be more homogeneous than expected, with good petrophysical properties. These conditions led to the evaluation of ML concepts, with an expected low impact on water-cut trends and water breakthrough. With the goal of increasing reservoir contact, the ML concept consisting of undulating counterphase dual laterals was tested in August 2013. The producer was modified to an undulating counterphase dual lateral throughout the two main sands. The injector maintained the original well concept in counterphase with the original producer mainbore. As a result, well production doubled with respect to the average before the intervention. In parallel, key development wells were identified for data acquisition and appraisal activities that have resulted in derisking stepout opportunities as well as assessing the potential of challenging resources, such as the peripheral areas.

Hydrocarbon potential, structural setting and depositional environments of Hammam Faraun Member of the Belayim Formation, Southern Gulf of Suez, Egypt

The Middle Miocene Belayim Formation is one of the most prolific formations in the Southern Gulf of Suez. It consists of four members; two members are evaporitic (Baba and Feiran) and the other two members are prospective, mostly clastics (Hammam Faraun and Sidri). The hydrocarbon potential and depositional environment of Hammam Faraun Member, the target of the present study, have been studied in 11 wells distributed in the southern province of the Gulf of Suez. The traditional well log data, as well as the Spectral Gamma-Ray logs ‘SGR’ and dipmeter data were used to evaluate the petrophysical properties and distribution of the Hammam Faraun Member in the Southern Gulf of Suez. It varies greatly in thickness with the greatest thicknesses in GS 365 (372 ft) and GS 373 (430 ft) fields in the central parts and the thinnest at the basin margins of the studied area at GH376 (65 ft) and Ras El Bahar (67.5 ft) fields. It is composed of clastic rocks, mainly shales and sometimes reef carbonates. The very good petrophysical properties of the studied sequence indicate a good reservoir in some fields with good to very good porosity (13.5 ≤ ∅ ≤ 25.0%). The shale volume of this reservoir sequence is less than 33% and the water saturation is less than 42.3%, while the net-pay thickness is up to 58 ft.The SGR and Pe logs indicate that, the studied rocks were deposited mostly in lagoonal to shallow marine environments, with illite and montmorillonite as dominant clay minerals.The dipmeter data obtained in some wells indicate slightly tilted beds, mostly less than 20° with an overall dip direction towards the SW, which represents the regional dip in the Southern Gulf of Suez. Based on dipmeter data, two major angular unconformities can be detected; one at the top of the sequence, separating it from the overlying South Gharib evaporates, and another one at the base of the sequence, separating it from the underlying Feiran Member.

Influence of hydrocarbon injection on the compaction by pressure-solution of a carbonate rock: An experimental study under triaxial stresses

The preservation of good petrophysical properties (high porosity/high permeability) at great depth in carbonate rocks may lead to the existence of a deeply buried reservoir (DBR), a target of interest for the oil industry. One of the key processes controlling diagenesis of the burial environment is Pressure Solution Creep (PSC), an efficient compaction process responsible for the evolution of porosity and permeability in many carbonate reservoirs. In this experimental study, we examine the effect of i) the presence of oil in the pore space and ii) its timing of injection on the PSC process and the petrophysical properties of a carbonate rock. The experiments were performed using a flow-through high-pressure cell, allowing the simulation of the pressure/stresses and temperature conditions of a DBR. Multi-disciplinary data (mechanical, chemical, petrographical and petrophysical) demonstrate that, without oil in the pore space, the main diagenetic process is the PSC, a process reducing by three the initial porosity but having no influence on intrinsic water permeability. An early injection of oil prior to water circulation causes the inhibition of PSC by the coating of the grains, leading to the preservation of porosity. Conversely, a late injection of oil does not preserve initial porosity. The dataset obtained from these experiments show the importance of the timing of oil charging in a reservoir in the preservation of initial porosity at great depth by the inhibition of PSC. However, the coating of grains by hydrocarbons may also inhibit further diagenetic processes leading to a creation of secondary porosity at depth.

Reservoir properties and seal efficiency in the Zubair Formation in Euphrates Subzone, Southern Iraq

The lower cretaceous Zubair Formation in Euphrates Subzone south of Iraq is divided into three members. These members are divided depending on the variation in lithology. The upper and lower members, which consist mainly of shale is known as Upper Zubair Formation and Lower Zubair Formation, respectively. The middle Zubair Formation consists mainly of sandstone. Intra-formation Zubair-shale are primarily seals, as well as source rock. The gained hard and software data are loaded into GeoFrame system. A trial is done to perform the formation evaluation for Zubair Formation on available data for nine wells. The created project contains all the operation of the reservoir properties. The quality of a sealing rock from both upper and lower is determined by the minimum permeability and effective porosity (less than 80 mD and 9 %, respectively). The sealing rock of Zubair Formation is mainly the shale rocks, which is an organic-rich elastic rock that may suppose to be efficient. On the other hand, the reservoir sand facies have good petrophysical properties. The average of effective porosity was 18 %; however, the permeability is at least 250 mD. The geological setting may supports the horizontal migration of oil to the western area along Abo-Jir fault to the stable shelf successions.

Reservoir characteristics and their effects on hydrocarbon accumulation in lacustrine turbidites in the Jiyang Super-depression, Bohai Bay Basin, China

A great difference exists between the hydrocarbon charging characteristics of different Tertiary lacustrine turbidites in the Jiyang Super-depression of the Bohai Bay Basin, east China. Based on wireline log data, core observation and thin-section analyses, this study presents detailed reservoir property data and their controlling effects from several case studies and discusses the geological factors that govern the hydrocarbon accumulation in turbidite reservoirs. The lacustrine fluxoturbidite bodies investigated are typically distributed in an area of 0.5–10 km 2, with a thickness of 5–20 m. The sandstones of the Tertiary turbidites in the Jiyang Super-depression have been strongly altered diagenetically by mechanical compaction, cementation and mineral dissolution. The effect of compaction caused the porosity to decrease drastically with the burial depths, especially during the early diagenesis when the porosity was reduced by over 15%. The effect of cementation and mineral dissolution during the late-stage diagenesis is dominated by carbonate cementation in sandstones. High carbonate cement content is usually associated with low porosity and permeability. Carbonate dissolution (secondary porosity zone) and primary calcite dissolution is believed to be related to thermal maturation of organic matter and clay mineral reactions in the surrounding shales and mudstone. Two stages of carbonate cementation were identified: the precipitation from pore-water during sedimentation and secondary precipitation in sandstones from the organic acid-dissolved carbonate minerals from source rocks. Petrophysical properties have controlled hydrocarbon accumulation in turbidite sandstones: high porosity and permeability sandstones have high oil saturation and are excellent producing reservoirs. It is also noticed that interstitial matter content affects the oil-bearing property to some degree. There are three essential elements for high oil-bearing turbidite reservoirs: excellent pore types, low carbonate cement (<5%) and good petrophysical properties with average porosity >15% and average permeability >10 mD.

Depositional environment and diagenesis as controlling factors for petro-physical properties and weathering resistance of siliciclastic dimension stones: integrative case study on the ‘Wesersandstein’ (northern Germany, Middle Buntsandstein)

Abstract A case study on the ‘Wesersandstein’ (Middle Buntsandstein) indicates that weathering resistance and quality of dimension stones are functions of depositional environment, and of diagenetic alterations (eogenetic as well as mesogenetic) during geological history. Two types of dimension stones, one deposited in a braided and the other in a meandering river system, were compared with respect to the fluvial architecture, the diagenetic modifications, the raw block prospectivity, and the petro-physical properties. The integrative synthesis of all these approaches indicates that depositional environment (type of fluvial architecture) and diagenesis (quartz cement and clay matrix contents) are the key processes which generally control the petro-physical properties and the weathering resistance of siliciclastic dimension stones. The highly quartz cemented ‘Grauer Wesersandstein’ with low clay matrix content, deposited as channel fill (braided river system), is characterized in general as a high quality dimension stone with very good petro-physical properties (e.g. high compressive strength, tensional strength, abrasion resistance, and freeze-thaw resistance) and high weathering resistance. In contrast to this, the ‘Roter Wesersandstein’, deposited as point bar and floodplain deposits of meandering rivers with low quartz cement and high clay matrix contents shows minor quality petro-physical properties (e.g. minor compressive strength, tensional strength, abrasion resistance, and freeze-thaw resistance) and weathering resistance. This new integrative approach combines hitherto isolated studies on dimension stone quality. It shows the complex interrelations between the geological background on the one hand and specific dimension stone properties on the other hand.