AAPG Bulletin Research Articles

Why does it take so long to publish a paper in the AAPG Bulletin?

Why does it take so long to publish a paper in the AAPG Bulletin?

Global Progress in Oil and Gas Well Research Using Bibliometric Analysis Based on VOSviewer and CiteSpace

Studies related to oil and gas wells have attracted worldwide interest due to the increasing energy shortfall and the requirement of sustainable development and environmental protection. However, the state of oil and gas wells in terms of research characteristics, technological megatrends, article-produced patterns, leading study items, hot topics, and frontiers is unclear. This work is aimed at filling the research gaps by performing a comprehensive bibliometric analysis of 6197 articles related to oil and gas wells published between 1900 and 2021. VOSviewer and CiteSpace software were used as the main data analysis and visualization tools. The analysis shows that the annual variation of article numbers, interdisciplinary numbers, and cumulative citations followed exponential growth. Oil and gas well research has promoted the expansion of research fields such as engineering, energy and fuels, geology, environmental sciences and ecology, materials science, and chemistry. The top 10 influential studies mainly focused on shale gas extraction and its impact on the environment. More studies were produced by larger author teams and inter-institution collaborations. Elkatatny and Guo have greatly contributed to the application of artificial intelligence in oil and gas wells. The two most contributing institutions were the Southwest Petr Univ and China Univ Petr from China. The People’s Republic of China, the US, and Canada were the countries with the most contributions to the development of oil and gas wells. The authoritative journal in engineering technology was J Petrol Sci Eng, in environment technology was Environ Sci Technol, in geology was Aapg Bull, and in materials was Cement Concrete Res. The keyword co-occurrence network cluster analysis indicated that oil well cement, new energy development, machine learning, hydraulic fracturing, and natural gas and oil wells are the predominant research topics. The research frontiers were oil extraction and its harmful components (1992–2016), oil and gas wells (1997–2016), porous media (2007–2016), and hydrogen and shale gas (2012–2021). This paper comprehensively and quantitatively analyzes all aspects of oil and gas well research for the first time and presents valuable information about active and authoritative research entities, cooperation patterns, technology trends, hotspots, and frontiers. Therefore, it can help governments, policymakers, related companies, and the scientific community understand the global progress in oil and gas well research and provide a reference for technology development and application.

Super basin thinking: Methods to explore and revitalize the world’s greatest petroleum basins

The AAPG Super Basin Initiative creates an action plan to help geoscientists revisit the world’s most productive petroleum basins by providing resources through conferences, online presentations, and publications like this special issue of the AAPG Bulletin. Understanding super basins better enables us to apply technologies that can reveal each unique super basin’s full resource development potential. By studying the world’s most significant petroleum super basins, we document concepts to find and produce hydrocarbons more economically in all basins. Between 2000 and 2015, game-changing technologies reinvigorated many of the world’s greatest onshore and offshore basins. Workflows that caused production peaks to reach new heights included horizontal drilling and hydraulic fracturing in unconventional onshore reservoirs and enhanced seismic imaging in conventional offshore reservoirs. Improved understanding of source rocks, petroleum systems, oil habitats, stratigraphy, rock properties, and clinoform architecture enhances the exploration and development toolkit. Reduced costs, improved processes, and multidisciplinary teams created a new golden age in many super basins. Super basin thinking forms a new paradigm useful in directing actions. Super basins foster technology advancement because they possess key geologic factors and a basin-level economy of scale that fuels innovation. New concepts and techniques and methodologies developed in super basins benefit the entire ecosystem of hydrocarbon recovery. As geoscientists, global thinking improves our ability to provide abundant and affordable energy choices and, when done correctly, can also benefit economies and our environment. Super basins, geoscientists, and AAPG play vital roles in this noble effort.

A new computational model for flow in karst-carbonates containing solution-collapse breccias

We develop a new three-scale (micro/meso/macro) computational model based on a reiterated homogenization procedure to describe flow in carbonate rocks containing complex geological structures, such as fractures and solution-collapse breccias in the sense of Loucks (AAPG Bull. 83(11), 1795–1834, 1999). In this setting, we construct a hierarchical karst-fracture model wherein the larger geological objects are incorporated explicitly whereas the higher density microscopic structures are homogenized and replaced by equivalent continua with properties computed from self-consistent homogenization schemes. In the upscaling method, we subdivide the different clastic arrangements in the breccia into crackle, mosaic, and chaotic substructures where equivalent permeability and elastic constants are assigned to each layer within the breccia. After reconstructing the mesoscopic coefficients, we adopt a flow-based upscaling to the macroscale, where the characteristic length is associated with a typical coarse grid cell of a reservoir simulator. The mesoscopic flow equations are constructed based on the discrete fracture model (DFM) and discretized by a robust computationally scheme with the ability to handle strong heterogeneity induced by the collapse breccia and pressure jumps across flow barriers. In addition to the scenario wherein the collapse breccia network is composed of disconnected objects (isolated chambers), we also develop a reduced model for the case of connected karst facies playing the role of a network of enlarged fractures. Numerical results, with input data extracted from outcrops drone images, are presented illustrating the influence of different settings on flow patterns and their effect upon the magnitude of macroscopic properties.

ГЕОЛОГІЧНІ РИЗИКИ ПРИ ОЦІНЦІ РЕСУРСНОЇ БАЗИ ВУГЛЕВОДНІВ

At the present stage of geological exploration, the issue of assessing the hydrocarbon resource base of promising facilities is not relevant on a deterministic basis, but using probabilistic assessments and geological risks, which is especially important when assessing investment attractiveness, especially when introducing international projects. Geological risk is associated with the uncertainty of the geological model of an oil and gas perspective object and does not depend on the absolute value of the estimated resources. Based on the analysis of world experience, preliminary studies of this issue in Ukraine and features of the geological structure and oil and gas content of the Eastern oil and gas region of Ukraine, the main geological risks are identified: - the risk of the existence of a trap - the probability that there is a structural or other form in which the position of the explosives may be contained, the reliability of the release of the trap according to available geological and geophysical data; - the risk of the collector's existence is the probability that the breed having sufficient porosity, permeability and spatial distribution in the predicted section of the cut is present and maintained in the process of development of mobile explosives; - the risk of the existence of a tire - the probability that promising in oil and gas bearing deposits overlapping rocks are impervious to predicted hydrocarbons and able to hold the deposit; - risk of regional (zonal) oil and gas - the probability that within the oil and gas prospect facility there are hydrocarbons in a specific productive horizon. For a more confident and unified determination of the risk factors for the existence of a trap, its dependence on the main characteristics of the predicted trap was developed. In addition to the type of trap, differentiation is performed depending on the depth of the object, its amplitude and the number of complicated tectonic disturbances and their type. In addition, recommendations have been developed for the use of methodological methods for determining the risks in assessing the hydrocarbon resources of oil and gas prospecting facilities, which will increase the reliability of the assessment of the resource base of promising objects in the Eastern oil and gas region of Ukraine. Key words: hydrocarbon, geological works, important evaluation, naftagazperspective objects, evaluation of risks, perspective resources References Galkin S.V. 2012. Methodology of accounting for geological risks at the stage of exploration and exploration of oil fields. Bulletin PNRPU. Geology. Oil and gas and mining. № 4. P. 23-32.https://doi.org/10.15593/2224-9923/2012.4.3 Кerimov V.Y., Bondarev А.V., Mustaev R.N., Hоshtaria V.N. 2017. Estimation of geological risks in searches and exploration of hydrocarbon deposits. «Oil industry». № 8. P. 36-41. Poliakov А.А. Systemic approach to the analysis and reduction of risk in the search and exploration of oil and gas fields. Oil and gas geology. Theory and practice. Т.11. №1. 22 p. www. URL: http://ngtp.ru/rub/3/3_2016.pdfhttps://doi.org/10.17353/2070-5379/3_2016 Popadiuk I. 2003. Theoretical bases for assessing geological risks in the oil industry according to world standards. Oil and gas industry. № P. 9-15. Kharchenko M.V., Vakarchuk S.G., Kitchka O.A. Accounting for geological risks practice while evaluating resource base of hydrocarbon Usage in Ukraine. Prospects for investing. Materials of the Third Scientific and Practical Conference (October 4-7. 2016. Truskavets). State commission of Ukraine on mineral resources (SCMR). К. SCMR. 2016. P. 243-246. Fokin 2011. Managing Exploration Risks & Uncertainties. https://rogtecmagazine.com/wp-content/uploads/2014/09/05_TNK-BP_Managing_Exploration_Risks.pdf Aigbedion I., Iyayi S.E., Agbeboh G.U. Prospect assessment and risk analysis: Example from Niger Delta, Nigeria Basin. International Journal of Physical Sciences. December. Vol. 3 (12). Р. 293-298. Colson T. Fault Seal Analysis: Constraining Fault Seal Risk Using Seismic Velocities. AAPG Search and Discovery Article #41789. Posted April 11. 15 p. Cunha A. 2011. Economic and Risk Analysis Applied to Petroleum Engineering. Recent Developments and Application Examples. SPE Distinguished Lecture Program presentation. 36 p. Mannini A., Rawstron P., Chai S.N., Spedding A. De-Risking a Gas Development Using Geophysical Methods. AAPG Search and Discovery Article #41086. Posted November 30. 2012. 16 p. Rose P.R. 2001. Risk Analysis and Management of petroleum exploration Ventures. AAPG Methods in Exploration Series. No. 12. Р. 172. The ССОР Guidelines for Risk Assessment of Petroleum Prospects. http:www.geosint.com/images/stories/geointelligence/technical/modeling/NORAD_RiskA.pdf White D.A. 1993. Geologic risking guide for prospects and plays: AAPG Bulletin. v 77. Р. 2048-2061.https://doi.org/10.1306/BDFF8FCE-1718-11D7-8645000102C1865D

Biomarker paleo-reconstruction of the German Wealden (Berriasian, Early Cretaceous) in the Lower Saxony Basin (LSB)

During the Early Cretaceous (Berriasian; Wealden 3–4), Northwestern Germany was covered by an east–west elongated tentatively brackish lake in which locally more than 700 m-thick black shales were deposited. While the distribution of organofacies’ in the basin is relatively well documented, the paleoenvironmental conditions in the basin center (e.g., occurrence and spread of water column stratification) and the spatial record of biomarkers in Wealden 3–4 shales (and coals) are rarely known. We here present respective data from the entire basin. In large areas, total organic carbon (TOC) contents are above 5 wt% and HI values above 700 mg hydrocarbons (HC)/g TOC, supporting the high potential of shales in the central basin as petroleum source rocks. Furthermore, bulk geochemical data as well as biomarkers clearly mirror the Wealden 3–4 facies distribution with the differentiation of a predominantly terrestrial setting east of the Weser River and an aquatic and brackish lake setting in the west. Certain biomarkers such as isorenieratane, specific for green sulfur bacteria, indicate that the basin consisted of a permanently stratified water column with a brackish/marine deep water body and an oxic–anoxic transition zone in the photic zone. In the southwestern gate of the lake (including the Isterberg area) and towards the east, no water column stratification developed. Characteristic of Wealden 3–4 black shale organic matter are: high relative abundances of saturated versus aromatic hydrocarbons (most likely due to high Botryococcus algal input), highly negative δ13C values in the extract fractions, low isotopic “canonical variables” (sensu Sofer in AAPG Bull 68:31–49, 1984), and high gammacerane, dinosterane, and C35-homohopane relative abundances. Interpreting those data, the different sub-facies of the environmental setting can be excellently documented. Particularly, in the western part of the basin, Wealden 3–4 shales are important petroleum source rocks. However, an overlap of biomarker signatures with those from Jurassic Posidonienschiefer Formation (“Posidonia”) shales from the same area shows that oil–source rock correlations in this area remain challenging.

Dealing with a rejection

Dealing with a rejection

Qualities of a good reviewer

Interpretation shares commonalities with Geophysics and the AAPG Bulletin in that it is a peer-reviewed journal. Unlike Geophysics and the AAPG Bulletin , Interpretation is built around special sections headed by a team of special-section editors who are either experts or particularly interested in

Geochemistry of late miocene-pleistocene basalts in the Phu Quy island area (East Vietnam Sea): Implication for mantle source feature and melt generation

Geochemistry of late miocene-pleistocene basalts in the Phu Quy island area (East Vietnam Sea): Implication for mantle source feature and melt generation

Quick Evaluation of Source Rock Kerogen Kinetics Using Hydrocarbon Pyrograms from Regular Rock-Eval Analysis

Source rock kinetics reflects kerogen reactivity that controls the onset and rate of hydrocarbon generation as well as the depth/temperature of oil and gas generation windows. Therefore, understanding source rock kinetics is critical to both quantitative resource modeling and identifying production “sweet spots”. The study of source rock kinetics requires special laboratory procedure and expertise, the cost of which limits research on specific source rock systems. For quantitative modeling of hydrocarbon generation, kinetic parameters are often adopted from an analogous source rock system available in published data sets or are automatically picked by basin modeling software based on kerogen type or depositional environment and facies. Recent studies (Peters, K. E., Walters, C. C., and Mankiewicz, P. J. AAPG Bull. 2006, 90, 387−403) revealed that source rock kinetics may vary substantially, even for the same type of kerogen, because of compositional variation. Thus, source-rock-specific kerogen kinetics i...

Faulting and fracturing in shale and self-source reservoirs: Introduction

Production from self-sourced reservoirs relies on natural and induced fracturing for permeability and conductance of hydrocarbons to the producing wellbores, thus natural or induced fracturing is often a key to success in unconventional reservoir plays. On the other hand, fractures may compromise seals and large or well-connected fractures or faults may cause undesirable complications for unconventional reservoirs. Natural and induced fractures are influenced by (1) mechanical stratigraphy, (2) pre-existing natural deformation such as faults, fractures, and folds, and (3) in situ stress conditions, both natural and as modified by stimulation and pressure depletion. This special issue of the AAPG Bulletin elucidates some of these structural geologic and geomechanical controls. Understanding the occurrence and controls on natural and induced faulting and fracturing in self-sourced reservoirs is a key component for developing effective approaches for exploiting self-sourced reservoirs.

Predicted bulk composition of petroleum generated by Lower Cretaceous Wealden black shales, Lower Saxony Basin, Germany

The Berriasian Wealden Shale provides the favourable situation of possessing immature to overmature source rock intervals due to differential subsidence within the Lower Saxony Basin. Hydrocarbon generation kinetics and petroleum physical properties have been investigated on four immature Wealden Shale samples situated in different depth intervals and following the PhaseKinetics approach of di Primio and Horsfield (AAPG Bull 90(7):1031–1058, 2006). Kinetic parameters and phase prediction were applied to a thermally calibrated 1D model of the geodynamic evolution at the location of an overmature well. The immature source rocks of all depth intervals comprise kerogen type I being derived from the lacustrine algae Botryococcus braunii. Bulk kinetics of the lower three depth intervals (sample 2–4) can be described by one single activation energy E a, typical for homogeneous, lacustrine organic matter (OM), whereas sample 1 from the uppermost interval shows a slightly broader E a distribution which hints to a more heterogeneous, less stable OM, but still of lacustrine origin. Predicted physical properties of the generated petroleum fluids are characteristic of variably waxy, black oil possessing GOR’s below 100 Sm3/Sm3 and saturations pressures below 150 bar. Petroleum fluids from the more heterogeneous OM-containing sample 1 can always be described by slightly higher values. Based on the occurrence of paraffinic, free hydrocarbons in the uppermost horizon of the overmature well and gas/condensate in the lower 3 depth intervals, two scenarios have been discussed. From the first and least realistic scenario assuming no expulsion from the source rock, it can be deduced that phase separation in the course of uplift can only have occurred in the uppermost interval containing the slightly less stable OM but not in the lower intervals being composed of a more stable OM. Therefore and taking secondary cracking into account, all depth intervals should contain gas/condensate. The free hydrocarbons in the upper horizon are interpreted as impregnation from migrated hydrocarbons. The second scenario assumes nearly complete expulsion due to fracturing by the so-called generation overpressure (Mann et al. in Petroleum and basin evolution. Springer, Berlin, 1997). The expelled petroleum might migrate into lower pressurised source rock horizons and reach bubble-point pressures leading to the exsolution of gas and “precipitation” of very high molecular weight bitumen unable to migrate. Subsequent burial of the latter in the course of the basin evolution would lead to secondary cracking and remaining pyrobitumen explaining the high amounts of pyrobitumen in the overmature well Ex-B and relatively enhanced TOC contents at such high maturity levels.

Modern internal waves and internal tides along oceanic pycnoclines: Challenges and implications for ancient deep-marine baroclinic sands: Discussion

In his article, “Modern internal waves and internal tides along oceanic pycnoclines: Challenges and implications for ancient deep-marine baroclinic sands” (Shanmugam, 2013), Shanmugam provides a very detailed account of processes involved in oceanic currents. He stresses that he has done this because he is concerned that the misinterpretation of baroclinic sands caused by turbidite deposits could have economic risks for the petroleum industry. As an example of one such possible misinterpretation, he refers to deep-water sands in the Kutei Basin in Indonesia that were described as turbidites by Saller et al. (2006). This is the second time that Shanmugam has questioned our interpretation published in the AAPG Bulletin (Saller et al., 2006). In his 2008 discussion (Shanmugam, 2008) and in his current 2013 article, he asserts that the Kutei deep-water sands might not be turbidites but instead might have been deposited by deep-marine tidal bottom currents. Shanmugam is well known for his decades of opposition to the turbidity-current model for deep-water sand deposition; those interested in this history can find pertinent references under the name Shanmugam in the reference lists of Shanmugam (2008, 2013). Of course, we replied to Shanmugam’s 2008 discussion (Saller et al., 2008a), where we noted that the purpose of our 2006 article was to document the presence of source rock–quality terrestrial organic matter within deep-water sands. Associated shales did not have high organic content. Cores from our deep-water discovery wells contained fining-upward sand layers with abundant fossil terrestrial-plant leaves. The total organic carbon content within some of these sand layers exceeded 5%, and the analysis of oil, gas, and condensate from our deep-water Kutei Basin discoveries indicated a land-plant source for the hydrocarbons, consistent with fossil leaves. We were pleased to present this information to the scientific community, in the hope that it might …

Dating petroleum emplacement by illite 40Ar/39Ar laser stepwise heating: Discussion

Isotopic dating of diagenetic processes in relation to hydrocarbon charge in buried sedimentary sequences is of importance to the oil industry. Yun et al. recently published in the AAPG Bulletin (v. 94, no. 6, p. 759–771) on that topic a study entitled, “Dating Petroleum Emplacement by Illite 40Ar/39Ar Laser Stepwise Heating Technique.” This study raises questions about basic aspects of 40Ar/39Ar dating fine-grained authigenic clay minerals, describes flawed methodology, and ignores important previous work. As isotopic dating of diagenetic processes may interest readers of the AAPG Bulletin that are not necessarily specialists in either isotopic geochronology or clay mineralogy, it appeared necessary to comment on both the technical aspects and the scientific interpretations of this study. We discuss especially the fact that the authors discarded 39Ar recoil followed by an evaluation of its impact on the results and the interpretations.

Sandstone reservoir quality prediction: The state of the art

Joanna Ajdukiewicz joined Exxon Production Research Company in 1980. She was Reservoir Quality Assessment and Prediction team lead there from 1991 to 1995 and at Imperial Oil Research Centre in Calgary from 1995 to 1997. Subsequently, she has worked a variety of Exploration Company assignments in the North Sea, Gulf of Mexico, and Middle East. Her current interests are in predicting the distribution of early diagenetic controls on deep reservoir quality. Rob Lander develops diagenetic models for Geocosm LLC. He obtained his Ph.D. in geology from the University of Illinois in 1991, was a research geologist at Exxon Production Research from 1991 to 1993, and worked for Rogaland Research and Geologica AS from 1993 to 2000. He is also a research fellow at the Bureau of Economic Geology. To guess is cheap; to guess wrongly is expensive (Chinese proverb). Reservoir-quality predictive models will be a useful element of risk analysis until remote-sensing tools are invented that accurately measure effective porosity and permeability ahead of the bit. This issue of the AAPG Bulletin highlights recent advances in a new generation of reservoir quality models that have successfully predicted porosity and permeability in diverse siliclastic reservoirs under many different burial conditions. Most previous attempts at predrill reservoir quality prediction have relied on empirical correlations or on first-principle geochemical simulations that incorporate laboratory-derived input parameters (Wood and Byrnes, 1994). The new reservoir quality models differ from previous approaches in that, although incorporating theory-inspired algorithms, they include terms with values that are explicitly designed to be calibrated by, and tested against, data sets of high-quality petrographic analyses that are linked to thermal and effective-stress histories. Petrographic observations therefore provide essential constraints in these models on the types, timing, and rates of key geologic processes affecting sandstone pore systems. This approach avoids the pitfalls inherent …

2009 Napa AAPG Hedberg Research Conference on Basin and Petroleum Systems Modeling

Marek Kacewicz is a research consultant with Chevron Energy Technology Company in Houston, Texas. Prior to joining Chevron, Marek worked as a research geologist for ARCO Exploration and Production Research Center in Plano, Texas, and worked as a basin modeler for Unocal Exploration and Exploitation Technology in Sugar Land, Texas. He has more than 20 years of experience in basin modeling, exploration, and research. His experience covers a wide range of geographic areas worldwide. Some of his professional honors include receiving the 1986 International Association for Mathematical Geology Vistelius Research Award, being selected as an Alexander von Humboldt Fellow (Germany), and receiving the 2005 AAPG Gabriel Dengo Memorial award. He has an M.S. degree in computer science/numerical mathematics and a Ph.D. in earth sciences, both from the University of Warsaw (Poland). Kenneth Peters is a geochemical advisor for Schlumberger. He is the principal author of The Biomarker Guide (2005, Cambridge University Press) and consulting professor at Stanford University where he leads the Basin and Petroleum System Modeling Industrial Affiliates Program. He is a chair of the AAPG Research Committee, AAPG distinguished lecturer for 2009 and 2010, associate editor for AAPG Bulletin and Organic Geochemistry , and editor for the 2009 AAPG Datapages publication Getting Started in Basin and Petroleum System Modeling . He is the recipient of the 2009 Schlumberger Henri Doll Prize for Innovation and the 2009 Alfred E. Treibs Award presented on behalf of the Organic Geochemistry Division of the Geochemical Society. He has a Ph.D. in geochemistry from the University of California, Los Angeles, and spent 15 years with Chevron, 9 years with Mobil and ExxonMobil, and 6 years with the U.S. Geological Society. David Curry is a senior geological advisor on petroleum systems in the Offshore Division at Devon Energy in Houston, focusing primarily on petroleum …

The function of fractures and in-situ stresses in the Khuff reservoir performance, onshore fields, Saudi Arabia

The highly variable performance of the Permian–Triassic Khuff reservoir in onshore Saudi Arabia has been attributed to the presence of natural fractures. Similar preproduction pressure profile and hydrocarbons in the different reservoir units in some fields have been attributed to vertical communication through large faults. To validate these assumptions, we studied the static and dynamic data from the Khuff reservoir in 19 major structural traps. We identified two distinctive fracture domains based on fracture orientation and density. Fracture evolution is mainly controlled by the extensional and consequent compressional plate tectonics instead of local structures. In-situ stresses are dominated by the Zagros plate tectonics and affect fracture aperture differently in the two fracture domains. The fracture impact on the Khuff reservoir performance is mostly subtle because of the nature and distribution of the fractures. High fracture-enhanced productivity occurs locally in some of the producing wells, and it results from high-density fracture clusters (including mesoscopic faults) with channel-type apertures. The following findings challenge the perceived major functions of fractures in the Khuff reservoir performance in onshore fields: (1) Individual fractures are dominantly tensile and small (mesoscopic and microscopic); (2) individual faults are small and not readily resolvable at seismic scale; (3) the depth and carbonate nature of the Khuff reservoir make the fractures highly susceptible to fast healing unless preserved within the hydrocarbon column; (4) initial vertical pressure gradient changes with production indicate a lack of present-day communication across the anhydrite sealing layers, between the different Khuff reservoir units; (5) horizontal well direction does not generally have an impact on productivity; and (6) sustained and heavy losses of circulation are rarely encountered in the Khuff reservoir wells. Mohammed S. Ameen received his Ph.D. and Diploma of Imperial College in structural geology and geomechanics from Imperial College, London, 1988. He has more than 20 years of academic and industrial experience and has patented a new method for the characterization of microfractured reservoirs. He has published 25 articles on fractures and folds, and has edited three special publications for the Geological Society (London). He conducted the first classic work on the fractures and folds across the Taurus-Zagros Range, Iraq, covering 30 major fold traps. The work is published in the AAPG Bulletin, the Geological Magazine, and the Journal of Petroleum Geology. He joined the Reservoir Characterization Department at Saudi Aramco in 1998. Since 2004, he has been leading the Structural Geology and Rock Mechanics Group in the Geological Technical Services Division, Saudi Aramco. He is an active member of the AAPG, Society of Petroleum Engineers, European Association of Geoscientists and Engineers, and the Geological Society (London). Ismail M. Buhidma is a petroleum engineering consultant in the Gas Reservoir Management Division of Saudi Aramco with 32 years of diverse industrial experience. For the last 12 years, he has been actively involved in Aramco's nonassociated gas development program. His areas of interest include reservoir management, well performance analysis, well test analysis, phase behavior, geomechanics, reservoir simulation, reservoir characterization, and well stimulation. Prior to joining Aramco, Ismail worked for Exxon in Libya, Schlumberger and Atlantic Richfield in the USA, and Qatar Petroleum in Qatar. Ismail holds B.S. and M.S. degrees in petroleum engineering from the University of Tulsa. He is a member of Society of Petroleum Engineers (SPE) and has published numerous SPE appears. Zillur Rahim is a petroleum engineering consultant with Saudi Aramco working in gas field development. He received his B.S. degree from Algerian Petroleum Institute and M.S. degree and Ph.D. from Texas A&M University, College Station, all in petroleum engineering. He has 25 years of industry experience, has published more than 50 technical papers, and has taught numerous industry courses. Previously, he worked with Holditch and Associates Petroleum Consultants and with Schlumberger Reservoir Technology group. His area of expertise includes reservoir engineering, hydraulic and acid fracturing, and reservoir management.

Structurally controlled hydrothermal dolomite reservoir facies: An overview: Discussion

One of the issues of the AAPG Bulletin (v. 90, no. 11) was concerned with “hydrothermal dolomite reservoirs,” specifically “hydrothermal dolomite fields” (Davies and Smith, 2006). The term “hydrothermal dolomite” is confusing and meaningless (Machel and Lonnee, 2002). To study the origin of dolomite and its hydrothermal depositional setting, I examined modern settings, including the Mediterranean Sea (Friedman, 1991) (Figure 1). The shallow-water facies in this modern setting consists of dolomite and gypsum. The rocks range from almost pure gypsum to pure tough dolostone so thoroughly cemented that sampling required hammer and chisel. X-ray diffraction analysis indicates the presence of minor anhydrite. Sporadic aragonitic gastropods occur, but fossils are otherwise absent. Under the microscope, it is a peloidal micrite (dolomicrite). The δ13CPDB of the dolostone is −39.3 to −31.2‰. These strongly negative δ13C values suggest that carbon of the dolomite came from methane. Methane forms when all sulfate has been reduced. Bacterial reaction was responsible for dolomite formation through the methane pathway. This syngenetic dolomite is like most dolomites of hydrothermal origin, but my students and I avoid this confusing bandwagon term. Figure 1 Approximate temperatures at which Holocene intertidal carbonate sediments formed, calculated from isotopic signatures. Three classes of dolostone have been recognized, which have been termed syngenetic, diagenetic, and epigenetic (Friedman and Sanders, 1967). The purpose of this classification has been for the orderly discussion of the subject and to facilitate descriptive study and genetic interpretation. The term “syngenetic” has been adapted for characterizing biological and chemical origin in its …

Comment on the Reply on “Theta map: Edge detection in magnetic data” ()

In their reply (Wijns et al., 2006) to a discussion (Li, 2006) of their paper (Wijns et al., 2005), stating Wijns et al. (2005) “…do not acknowledge several very relevant works…,” Wijns et al. (2006) state, “Although the works…are indeed relevant to our research, the authors have unfortunately not chosen to make these particular papers available in the scientific literature through publication in refereed journals. We must point out…that extended abstracts are not peer reviewed, and the general academic rule is that they are not suitable for referencing. Many journals reject abstract references outright.” Surprised by the lack of editorial comment on this and having just reread the 1986 SEG Expanded Abstract by Alford (1986), I entered “RM Alford” under “Author” at http://scholar.google.com/advanced_scholar_search and found that this abstract had been cited more than 50 times, including citations in articles in the AAPG Bulletin , CSEG Recorder , Geophysical Journal International , Geophysical Prospecting , GEOPHYSICS, Pure and Applied Geophysics , Revue de l’Institut Francais du Petrole , and Wave Motion . It appears that many of the journals of interest to geophysicists do not follow the “general academic rule” referred to by Wijns et al. (2006).

Structurally controlled hydrothermal alteration of carbonate reservoirs: Introduction

Langhorne “Taury” Smith heads the Reservoir Characterization Group at the New York State Museum. He holds a B.S. degree from Temple University, a Ph.D. from Virginia Tech, and did postdoctoral work at the University of Miami. He also worked for Chevron as a development geologist, and current research interests are focused on carbonate reservoir characterization and hydrothermal alteration of carbonate reservoirs. Graham Davies received his B.Sc. (honors) degree and Ph.D. from the University of Western Australia. His doctoral thesis was on modern carbonates in Shark Bay, Western Australia (published in AAPG Memoir 13). After a postdoctoral fellowship with James Lee Wilson at Rice University, he joined the Geological Survey of Canada (GSC) in Calgary. After 7 years with the GSC, Graham co-founded and became principal owner of AGAT (Applied Geoscience and Technology) Consultants/Laboratories. Since 1983, he has operated through GDGC Ltd. He has published about 70 papers on the geology of Australia and Canada, and has authored or coauthored more than 600 consulting reports. Graham received the CSPG Douglas Medal in 2002 for his work on Arctic Paleozoic carbonates and evaporites, and on the Triassic and other aspects of western Canadian geology. His principal current interest is in hydrothermal dolomites. This issue of the AAPG Bulletin is dedicated to structurally controlled hydrothermal alteration of carbonate rocks and reservoirs. This type of alteration covers the spectrum of carbonate-hosted sulfide ore deposits to hydrothermal dolomite to leached limestones, and in many cases has a major impact on reservoir type, geometry, quality, and distribution. Hydrothermal dolomite (HTD) reservoirs have a long history of exploration and development in North America, extending from the earliest discoveries in the Ordovician Lima-Indiana and other trends of the northeastern United States (Hurley and Budros, 1990; Wickstrom et al., 1992), and continuing today with the Trenton–Black River play …