Africa (Sub-Sahara) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Shchetinina, N. V. (Tyumen Petroleum Research Center) | Malshakov, A. V. (Tyumen Petroleum Research Center) | Basyrov, M. A. (Rosneft Oil Company) | Zyryanova, I. A. (Rosneft Oil Company) | Ganichev, D. I. (Rosneft Oil Company) | Yatsenko, V. M. (Rosneft Oil Company)
The article addresses the evolution history of interpretation of logging data from horizontal wells in Russia and abroad. Key problems of interpreting logging data are analyzed. It also describes the application of new technologies and approaches that have increased the validity of logging interpretation. The authors substantiate the need to integrate the full spectrum of geological and geophysical information. Further ways to develop approaches are proposed.
Twenty-one national geological surveys contributed to the European wide project ‘EU Unconventional Oil and Gas Assessment’ (EUOGA). The goal of EUOGA was to assess all potentially prospective shale formations from the main onshore basins in Europe and included contributions of twenty-one European geological surveys. Each participating geological survey characterized their domestic shale plays using thirty systematic parameters such as areal distribution, structural setting, average net to gross ratio of the shale reservoir, average Total Organic Carboncontent (TOC) and average mineralogical composition. The assessment covers 82 geological formations from 38 basins. Subsequently a stochastic volumetric probability assessment was performed on 49 of these formations which met the prerequisites for assessment. Importantly, this study for the first time used a unified methodology for assessing resources across European borders. Paleozoic plays in Poland, the United Kingdom, Denmark and Ukraine hold the largest potential gas resources. Most shale oil potential is observed in Bulgaria, the United Kingdom and Ukraine. The total resource potential for the geological formations that were evaluated in the project is 89.2 trillion cubic meter of gas initially in place (GIIP P50) and 31.4 billion bbl of oil initially in place (OIIP P50). The outcome of this project represents the most complete and accurate determination of shale hydrocarbon resources in Europe to date.
Europe may hold significant volumes of unconventional hydrocarbons as has been showed by both national and international agencies (e.g., EIA 2011, 2013, van Bergen 2013, Andrews 2013, 2014 , BGR 2012, Ladage 2016, PGI-NRI 2012). Interpretation and comparability of these studies is problematic, primarily due to difference in assessment methodology and both the quality and quantity of geological data that was available for the different plays. As a consequence the total European shale resource potential remains uncertain making long term planning, both political and economic, difficult. To overcome this problem a uniform assessment of European shale resources was required tailored to the specific challenges of the European situation.
Permeability estimations based on core-to-log relationships in dual-porosity carbonate reservoirs usually fail to reach the permeability measured on drillstem tests (DST). The reasons behind this inaccuracy are mainly related to the inherent low representability of rock samples in such systems and to the limitations of the logs in the presence of structures, such as caves and vuggy fractures. Conversely, high-resolution ultrasonic borehole image logs provide not only an image of the mega- and gigapore system present in dual-porosity reservoirs but also have been used empirically to identify the permeable facies within them. These logs have been widely used to identify fractures and caves normally related to fluid losses during the drilling operations but so far have not been used to estimate the permeability of such structures. Thus, the challenge of this study was to develop a quantitative method for permeability estimation using ultrasonic image logs as an input and to reach an acceptable calibration with matrix permeability measured in the laboratory as well as the whole system permeability measured in the DSTs. Ultrasonic-image-derived estimated permeability curves were calculated for three different wells drilled in karstified carbonate reservoirs and reached a very satisfactory calibration with matrix permeability measurements and permeability estimated on DSTs.
Carbonate reservoirs have a wide range of textural and structural variations in their framework elements and pore systems that may have been created by syngenetic, diagenetic and superimposed deformational processes. This is the case for naturally fractured reservoirs and karstified reservoirs, in which different scales of porosity are present: the matrix scale and the fractures/vugs scale (Warren and Root, 1963). Such variations on the scale of porous media address heterogeneities to the reservoir flow properties that cannot be efficiently quantified in the laboratory, making it difficult to tie those properties to the ones registered by DSTs. Permeability estimation based on the NMR log also fails to reach the order of magnitude measured in DSTs due to the log/tool limitation in the presence of caves and vuggy fractures.
Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases - CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S - were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl–, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42–). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and =3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.
Silurian black shales in Central and Eastern Europe (CEE) attracted lots of companies interested in unconventional shale gas exploration.The present day collage of various Silurian basin fragments in CEE is the result of several orogenic and rifting/drifting episodes. The proper paleogeographic reconstruction of a single, very large Silurian foredeep basin in the context of basin-scale geology has a major impact on the ongoing unconventional shale gas exploration efforts in the broader region.
The distal segments of a large Silurian foreland basin associated with the Caledonian collisional orogene, along the perimeter of the East European Craton, can be reasonably followed along strike from NW to SE, from Poland all the way to the Ukrainian Black Sea coast. The foredeep basin sequence onlaps to the NE the various pre-Silurian and crystalline basement units. The Silurian basin of the CEE is interpreted here as a pro-foreland basin, with short-lived (less than 15 m.y.) and extremely rapid (locally more than 1,500 m per m.y.!), accelerating subsidence histories recording only a portion of the orogenic history of the Caledonian orogeny. Besides the typical subsidence curves and prominent onlap onto the craton, the flexural origin is also supported by the general lack of normal-faulting within the basin, contradicting interpretations suggesting deposition on the passive margin of the Rheic Ocean. The map-view distribution of the lithofacies within the basin, such as clastic turbidites in the southwestern perimeter of the basin, deepwater shales in the center and neritic carbonates on the northeastern foreland margin, is also consistent with the flexural basin interpretation. This new interpretation may have some predictive power as to the temporal and spatial distribution of sweet spots for unconventional exploration targeting Silurian black shales in the broader CEE region.
Du, Linlin (Orient Baolin Technology Development (Beijing) Co.) | Chen, Shouyu (Orient Baolin Technology Development Co.) | Song, Bo (Orient Baolin Technology Development (Beijing) Co.) | Xiu, Shuzhi (Oil Production Technology Research Institute of Huabei Oilfield Co. PetroChina)
Classic hydraulic fracturing analysis is based on tensile strength of rock, failure criteria of fracture mechanics or Mohr-Coulomb criteria. The existing hydraulic fracturing theories consider little of permeability of fracture reservoir and effective fracturing range, which is exactly the purpose of fracturing. On the other hand, when evaluating effect of massive hydraulic fracturing (MHF), there may be lots of fracture initiation points and cracks due to large range of MHF, which brings huge challenges to numerical calculation of hydraulic fracturing.
MHF will have an effect on a large range of reservoir and accompany in-line micro-earthquakes, which indicate that lots of hydraulic fractures of different scales and directions are generated. Therefore, there will be difficulties to analyze cracking and propagating and estimate geometrical parameters by tensile criteria or fracture criteria. Even if the classic method is feasible, processing of element grid after rock failures will be a problem.
Aguilera (1995) considered shear failure criteria as failure criteria of rocks and proposes fracturing theory of divergent or branched cracks, and that explains the generation of in-line micro-earthquakes in hydraulic fracturing. But the present analysis is just a qualitative method but not quantitative method.
In fact, the basic goal of hydraulic fracturing is enhancing permeability of reservoirs as large as possible rather than producing one or two fractures. Analysis of fracturing effects is analyzing the influence of effective fracturing range on reservoir permeability. While the existing hydraulic fracturing theories just consider propagations and fracture initiations of one or two cracks but little of the quantitative estimation for effective fracturing range.
Hence it is necessary to find a better mechanical method to make up deficiencies of the existing fracturing analysis and overcome the difficulties of processing element grid after rock failures.
This study introduces continuum damage mechanics (Gurson damage model) to hydraulic fracturing, analyzes theories and techniques of hydraulic fracturing of porous reservoirs in terms of continuum damage mechanics and discusses damage effects of hydraulic fracturing to reservoirs. An analysis evaluation system of hydraulic fracturing continuum mechanics is set up, and by using damage theories, a method of analyzing hydraulic fracturing in fissured porous reservoirs is discussed.
Hydraulic fracturing theories are divided into two schools (Aguilera, 1995): The conventional school believes that hydraulic fractures are perpendicular to minimum principal stress and the prior research is the discussion of one or two fractures' initiations and propagations near wellbore. Three problems mainly solved are (Gidly, 1995; Economides, 2000; Wang and Zhang, 1998): fracture criteria, the direction of fracture propagation and the geometry of hydraulic fractures. Fracture criteria includes tensile strength criteria and fracture mechanics criteria.
Summary An approach of integral geological and geophysical modeling has been applied to study the Black Sea (south of Odessa Gulf and offshore Crimea Peninsula) shelf and continental slope to delineate its potential hydrocarbon prospects and leads. Geophysical 3D Earth model was built integrating all available geo-data including geodynamic studies, seismic, well and gravity data. Verification of the model with known gas fields proved correctness of the model built and reliability of new prospects. One of the most promising prospect mapped within continental slope and toe corresponding with higher probability to a submarine Neocomian canyon and fan incised into Jurassic bedrock. Method and its realization Interpretation process includes construction of heterogeneous 3D density model as the result of inverse problem solution for gravity data in combination with seismic data, well log data and other geological information (Petrovskyy O.P., 2005).