Khuff Gas Research Articles

Performance evaluation of novel thioctic acid conjugate as green corrosion inhibitor of L80 carbon steels in down pipes used in Khuff gas environment

The performance of a thioctic acid (TA) conjugate [ Chemical name is 5-(1,2-dithiolan-3-yl)-N-(6-ethoxybenzo thiazol--2yl) pentanamide [TA-2A-6E-BT], as green corrosion inhibitor for carbon steel (L80) sheets in Khuff gas media was demonstrated using experimental techniques viz. weight loss, potentiodynamic polarization, electrochemical impedance spectroscopy. Obtained results from experimental data are well corroborated with quantum mechanical calculations. Synthesized green corrosion inhibitor, TA-2A-6E-BT based on natural building block, has not been reported previously in the literature. This novel scaffold retarded the degradation of carbon steel (L80) in Khuff gas media which is experimentally substantiated by above characteristic studies. With regard to its mechanism of inhibition of corrosion, based on the polarization study parameters, the inhibitor is demonstrated to have performed as mixed mode inhibitor.

A facies and palaeogeography-based approach for analysis of petroleum systems in United Arab Emirates

The United Arab Emirates (UAE) is the 8th largest oil producing country and is rich in oil and gas resources. By the end of 2015, 68 oil and 23 gas fields had been discovered. The initial proved and probable (2P) oil, gas and condensate reserves amount to 81,135.9 MMb (million barrels), 192.09 Tcf (trillion cubic feet), and 6496.58 MMb respectively, which are mostly reservoired in the Jurassic and Cretaceous carbonates. With the latest field data, this study attempts to document the salient features of petroleum systems in UAE. Based on depositional facies of source rock intervals, pods of source rocks were delineated. On the basis of an oil- and gas-source correlation, five known petroleum systems were identified and they are Lower Silurian−Upper Permian Khuff gas, northeast foreland Upper Jurassic−Lower Cretaceous gas, Upper Jurassic–Jurassic petroleum, Upper Jurassic/Lower Cretaceous−Lower Cretaceous composite petroleum, and Middle Cretaceous−Middle to Upper Cretaceous/Cenozoic petroleum systems. Of them, the Upper Jurassic/Lower Cretaceous−Lower Cretaceous composite petroleum system contains 73.2% of the total 2P reserves and thus it is the focus of this study. The Upper Jurassic and Lower Cretaceous source rocks consist of argillaceous limestone, mudstone and shale, which were deposited as intrashelf basin facies. The distribution of oil and gas in this system is controlled by the source kitchens and the regional evaporite seal.

Technology Focus: Well Construction (May 2012)

Technology Focus The number and economic contribution of unconventional (tight gas/shale and steamflood) wells continued to increase rapidly in 2011, as did the participation of major operators. That increased industry focus was evident again in the distribution of papers. Also, there were more papers relating advances in plug-and-abandonment, Arctic, high-pressure/high-temperature (HP/HT), and carbon-capture technologies. Manny Gonzalez, Chevron Energy Technology Company’s Alliance Manager, noted that the huge interest in shale-formation completions calls for efficient controlled fracturing technology to ensure economic viability and an environmentally responsible well completion. SPE 152185 outlines a direct comparison of openhole vs. cased-hole fracturing in a tight gas reservoir. The presented results are surprising, and the effects on incremental production, fracture height, and fracture half-length are significant—a good read. Operators have been plugging nonproductive and storm-damaged wells at an increasing rate, and effective abandonment operations can prove costly and challenging. SPE 148640 relates a novel and well-detailed approach to a more efficient plug-and-abandon process and to the process of confirming plug integrity across an uncemented section of annulus. Check it out. Industry emphasis on long-term well reliability has continued to increase, especially for steamflood projects. SPE 150022 details a very thorough look into the many design and operational factors that affect well reliability in a high-temperature (285°C) steamflood. While only briefly mentioned, the authors undertook controlling the rate of temperature change, and thus controlling temperature disparity (∆T) between casing, cement sheath, and formation during injection cycles. Controlling injection events can have a strong effect on the reliability of a steamflood well or even a deepwater or HP/HT well. This is the first field effort at controlling such events that I recall. Recommended additional reading at OnePetro: www.onepetro.org. CMTC 152259 The Cement-Industry Roadmap To Reduce Carbon Emissions by L. Barcelo, Lafarge, et al. SPE 148639 An Integrated Fluids Approach To Enhance Zonal Isolation in Deep Khuff Gas Producers and Injectors Offshore Abu Dhabi by Mohammed A. Mehtar, SPE, Abu Dhabi Marine Operating Company, et al. IPTC 14913 A Paradigm Shift in Testing and Completion of Deep HP/HT Exploration Wells—Polished-Bore Receptacle (PBR) Improves Results and Operational Flexibility by Anwar Ibrahim, Kuwait Oil Company, et al.

Field-scale geometries of Upper Khuff reservoir geobodies in an outcrop analogue (Oman Mountains, Sultanate of Oman)

ABSTRACT This paper provides data on the lateral continuity and geometry of potential reservoir geobodies in outcrops of Upper Khuff Formation time-equivalent strata in the Jebel Al Akhdar area (Oman Mountains, Sultanate of Oman). It presents outcrop-based quantitative data of shoal-associated grainstone bodies in a sequence stratigraphic framework on the scale of an average Khuff gas field. Such data may be useful for correlation and modelling of subsurface reservoirs. A stratigraphic correlation of five outcrop sections, based on facies, sequence analysis and gamma-ray pattern, was used as a framework for mapping the distribution and lateral extent of grainstone geobodies over an area of 8 × 8 km. Four grainstone bodies were traced laterally along distinct marker beds over several hundreds of metres. The stratigraphic architecture shows a general layer-cake pattern. The thickness and lateral extent of reservoir geobodies is strongly influenced by their stratigraphic position. High-energy shoal facies developed preferentially in the regressive parts of cycles of multiple hierarchies. Individual grainstone bodies may reach a thickness of 6 m, and those thicker than 3 m extend across the area of interest. Clinoforms or shingle-type geometries were explicitly searched for, but were not present. The observed systematic variations in extent and two-dimensional sedimentary architecture of Khuff grainstone bodies were used as input for 3D static facies modelling. Outcomes of this study have been used to reduce uncertainty on grainstone geometries, production-scale correlation strategies and definition of lateral facies successions in subsurface models of the Khuff reservoir.

Integrated 3D reservoir modeling for Permian Khuff gas development in Ghawar Field, Saudi Arabia

Prolific gas production originates from the Permian Khuff carbonate reservoirs in the Ain Dar/Shedgum area of Saudi Arabia's giant Ghawar Field. However, well productivity is highly variable due to rapid lateral variations of porosity and permeability, which are mainly controlled by changes in depositional facies and diagenesis.

The effects of thermochemical sulfate reduction upon formation water salinity and oxygen isotopes in carbonate gas reservoirs

Thermochemical sulfate reduction (TSR) is a well known process that can lead to sour (H 2S-rich) petroleum accumulations. Most studies of TSR have concentrated upon gas chemistry. In this study we have investigated palaeoformation water characteristics in a deep, anhydrite-bearing dolomite, sour-gas reservoir of Permian age in Abu Dhabi using fluid inclusion, stable isotope, petrographic, and gas chemical data. The data show that low salinity, isotopically-distinct water was generated within the reservoir by reaction between anhydrite and methane. The amount of water added to the reservoir from TSR, indicated by reduced fluid inclusion salinity and water δ 18O values, varied systematically with the extent of anhydrite reaction with methane. Water salinity and isotope data show that the original formation water was diluted by between four and five times by water from TSR. Thus, we have shown that large volumes of very low salinity water were generated within the gas reservoirs during diagenesis following gas emplacement. The salinity of formation water in evaporite lithologies is, therefore, not necessarily high. Modelling, based upon a typical Khuff gas reservoir rock volume, suggests that initial formation water volumes can only be increased by about three times as a result of TSR. The extreme local dilution shown by the water salinity and δ 18O data must, therefore, reflect transiently imperfect mixing between TSR water and original formation water. The creation of large volumes of water has important implications for the mechanism and rate of thermochemical sulphate reduction and the interpretation of gas volumes using petrophysical logging tools.

Impact of crude oil production on the petrochemical industry in Saudi Arabia

The gas input into the petrochemical industry in Saudi Arabia involves mainly methane and ethane as fuels and feedstocks. These gases are produced from the separation of natural gas into its components. The majority of the natural gas produced in Saudi Arabia is as an associated gas. But the associated-gas production is heavily tied to crude-oil production. The impacts of various oil-production levels on the availability of methane and ethane have been studied by using a linear-programming model. With the existing demand for methane (1.62 × 10 9 SCFPD) and ethane (2.87 × 10 8 SCFPD), the minimum oil production is four million barrels per day. At this level of production, the methane demand is satisfied while there is an excess of ethane. But by the substitution of the excess ethane for a part of the methane demand, the minimum oil production could be reduced to three million barrels per day. Finally, by utilizing the maximum existing capacity of unassociated gas (1 × 10 9 SCFPD) from gas wells, the minimum oil production level can be reduced to one and one half million barrels per day. With more exploration and discoveries of Khuff gas, natural gas production will become even less dependent on oil production.

Forty-Seven Years' Gas Injection in a Preferentially Oil-Wet, Low-Dip Reservoir

Summary. Crestal gas injection has been used since 1938 for pressure maintenance in a preferentially oil-wet reservoir in the Bahrain field. This paper updates the gas injection history through July 1984, presents the benefits of gas injection, and discusses the finding that recovery in the gas-contacted area was greater than in water-invaded blocks. Introduction This is an update of two previous papers by Cotter and Shehabi. The Mauddud is the major oil-producing reservoir of the Bahrain field situated in an anticlinal feature of the Middle Cretaceous period. This is a highly undersaturated, low-dip, and preferentially oil-wet reservoir. Crestal gas injection has been used in the central block of the reservoir since 1938 for pressure maintenance, making it the first improved recovery project in the Arabian Gulf region. Numerous low-relief faults place the prolific Mauddud in juxtaposition with overlying, and underlying reservoirs. This provides additional production outlets for fluids. Initially, 0.2 PV of rich Arab-zone gas were injected from 1938 to 1973; this has been followed by lean Khuff gas. As of July 1984, 77% of the productive central block had been contacted by gas: the volumetric contact is 32%. Recovery in the contacted block is by a combination of gas drive and gravity drainage, whereas in the noncontacted north and south blocks, it is by water drive. Performance to date indicates much higher recovery in the Performance to date indicates much higher recovery in the gas-contacted central block than in the water-invaded north and south blocks. Reservoir analysis, including simulation, indicated improved oil recovery with higher gas injection. Accordingly, gas injection rates were increased by 40%, and more recently, an aggressive workover program was initiated to lower perforations and reduce free gas production. This has resulted in a rise in reservoir pressure, thus production. This has resulted in a rise in reservoir pressure, thus reversing peripheral water encroachment and maintaining oil production with no decline since mid-1983. As a result of the attractive response to gas injection in the central block. gas injection will be initiated soon in both the north and south blocks. This paper, while reviewing the gas injection history, presents the benefits of gas injection and describes the methods used to calculate the recovery factor in both gas-contacted and waterinvaded areas. Geology Lithologically, the reservoir rock is moderately soft to hard, fine-to-medium grained, fossiliferous. detrital, clean limestone. Much of the original rock has been altered by recrystallization and leaching. Leaching resulted in the creation of vugs and interconnecting channels. This makes the Mauddud formation an excellent reservoir with high porosity and uniform permeability. The reservoir has a porosity and uniform permeability. The reservoir has a fairly uniform thickness, averaging 110 ft [33.53 m], all of which is considered net pay. This reservoir is a highly faulted. elongated anticline with dips as low as 5 degrees [0.09 rad]. There are numerous faults in the crestal area with fewer on the flanks and on the north and south plunges. The displacement of the majority of the faults is less than 30 ft [9.14 m]. Because the thickness of the reservoir is 110 ft [33.53 m], it is in juxtaposition with other zones across the faults and possibly in communication with them. Fig. 1 is a structural possibly in communication with them. Fig. 1 is a structural cross section drawn cast/west across the reservoir. The two major faults with displacement above 50 ft [15.24m ] separate the central block from the north and south blocks. These faults, plus the extended distance from the crestal injection location. prevent the expansion of the gas cap into these remote areas. Reservoir Characteristics Rock Properties. Rock and fluid properties of the reservoir were reported earlier by Cotter. Essentially, he reported the average porosity and permeability as 25% and 40 to 60 md, respectively. There are no impermeable intervals to affect vertical permeability. Shehabi concluded, from laboratory investigation of preserved cores, that the reservoir is preferentially oil-wet. Because of the very rare occurrence of an oil-wet system worldwide, serious doubts are expressed and deliberated whenever such data are presented. To reconfirm the earlier observations, new laboratory studies were conducted recently for wettability determination. This time the studies were made on "fresh" (not cleaned before testing) core samples by Aniott's method. The results indicate a wettability index to oil of 0.60 and to water of 0.002. JPT P. 363

Design of Surface Facilities for Khuff Gas

Summary Although it was discovered in 1947, commercial exploitation of the Bahrain Khuff reservoir began in 1970. Current gas demand stands at 580 MMscf/D [16.4 × 106 std m3/d] and is growing rapidly. This paper briefly discusses the evolution of the design for surface facilities and field experience. The established design parameters could be used for the design of surface facilities for similar reservoirs.

Corrosion Monitoring and Inhibition in Khuff Gas Wells

Corrosion Monitoring and Inhibition in Khuff Gas Wells

CARBONIFEROUS OIL AND GAS PRODUCTION IN THE EASTERN HEMISPHERE ‐ 1

Almost all production from Carboniferous formations in the Eastern Hemisphere comes from the Soviet Union, with less importantproduction from the United Kingdom, the Southern North Sea basin, the N W German basin (from the northern Netherlands to Poland), Algeria, Ghana, the Gulf of Suez, China and Australia. However, Carboniferous coals extending from the eastern part of Great Britain to Poland were the source of the hugegas reserves that are found in Permian and Triassic reservoirs in the Southern North Sea‐N W German basin complex. Production of oil during 1978 was approximately 2,680,000 b/dt and of gas, about 20.8 Bcfldf. The USSR share was about 2.6 MM brl and 5.2 Bcf per day. Carboniferous production, which peaked in 1975, has since declined steadily.Most of the USSR's Carboniferous production is from marine carbonates andfrom marine to deltaic sandstones in the Volga‐ Urals, Timan‐Pechora and Dnepr‐Donets basins. The latter basin is mainly gas productive. Smaller amounts of hydrocarbons arepresent in marine beds of the North Caspian (Pricaspian) basin of the European USSR and in similar strata of the Chu‐Sarysu basin of Kazakhstan. Some small, but significant, discoveries have been made in carbonates of the southern part of the West Siberian basin. Although the deep Khuff gas of the Middle East is probably mainly of Permian origin, some Late Carboniferous source materials could have generated part of the gas, inasmuch as the base of the Khuff is probably Late Carboniferous.Hydrocarbons in terrigenous Carboniferous rocks in Egypt are believed to have originated in non‐Carboniferous beds; the petroleum in the Carboniferous sandstone reservoirs of Ghana, China and Australia is generally indigenous, and is non‐marine to deltaic. Oil and gas in the Carboniferous strata of Algeria are in marine and deltaic beds and are partly indigenous. The huge Carboniferous gas reserves in Permian, Triassic and, to a lesser extent, Carboniferous reservoirs of the Southern North Sea‐NW German basin are of non‐marine origin. The source materials were the Upper Carboniferous coals of the same area.The volume of produced Carboniferous oil is about 23 B brl, 21 B brl of it from the Volga‐Urals basin alone. About 63 Tcf of gas has been produced, 51 Tcf from the Southern North Sea‐NW German basin. This volume of gas includes Carboniferous gases in Permian and Triassic reservoirs. Proved and probable reserves of Carboniferous oil are about 13 to 14 B brland 85 Tcf, of which more than 50 Tcf remains in the Netherlands “giant Groningen Barents Sea extensions of the Timan‐Pechora basins, and ‐just possibly ‐ in several Chinese basins. The Arabian Gulf(Persian Gulf) also has a very largegas potential, but thegas, mainly in the Khuff, is of unknown origin and may wellnot be Carboniferous. (The Chu‐Sarysu basin, USSR, could also be important.)

Khuff formation Permian-Triassic carbonate in the Qatar-South Fars arch hydrocarbon province of the Persian Gulf

Since the 1948 discovery of prolific gas reservoirs in Bahrain, Middle East explorationists have been interested in the Khuff Formation (Permian-Triassic carbonate). Several supergiant gas fields (reserves above 10 tcf) have been found in the region. North of the Persian Gulf very large gas fields have been discovered in Permian strata of south Iran, especially in coastal Fars, such as Kangan, Dalan, Nar, Aghar, Bandubast, Mand, Varavi, Asaluyeh, as well as in the Persian Gulf. Qatar-South Fars province contains light and heavy crude oil ( Bashari, 1988), in addition to being one of the most important gas provinces in the world. Qatar’s North field is the largest of all the giant Khuff gas reservoirs, with total reserves of 436 tscf and field life of around 200 years at planned production rates. It covers an area of 6000 km2. The gas reservoirs are found at shallow depth in the Khuff, usually between 2470 and 2830 m below sea level (Al-Marri and Al-Bader, 1989). In fact the field is even bigger than indicated because its reservoir extends across the political boundary in the Persian Gulf under Iranian waters (South Pars Field). There are efforts to evaluate extensions of the field in Qatar waters, especially to the east and southeast of production areas. There is a strong probability that current reserves in the North field will increase as a result of such work (Al-Attayah, 1998). In 1992, Iran discovered the supergiant South Pars field, in the Persian Gulf, close to Qatar’s North field, (Fig.1). South Pars has reserves estimated at 436 tscf. (Petropars, 2005). The South Pars field is formed by an extremely large open periclinal structure. North field and South Pars fields overlie the broad Qatar arch, which subdivides the Khuff depositional basin, into two basins located north west and south east of the arch. This paper describes the Khuff carbonates distributions in terms of Lithostratigraphy- Biostratigraphy, (diachroneity) of this formation and also reservoir development of Khuff formation.