Non-reservoir Rocks Research Articles

Anomalous elastic properties of mudrocks bounding reservoirs with high concentrations of naturally occurring CO2

Very high concentrations of CO2 have been encountered in solution as carbonic acid in hydrocarbon reservoirs in parts of the Greater Sarawak Basin, offshore Borneo, Malaysia. Concentrations can exceed 80%. Anomalous features in 3D seismic data also are found in areas with high CO2 concentrations. These features appear as halos around reservoirs, cutting across stratigraphy and indicating a hardening of the nonreservoir rocks within the envelope of the halo. These halos can extend for hundreds of meters above and below a reservoir. Elastic log data from wells that pass through and adjacent to these seismic anomalies indicate that mudrocks within the anomalies have higher densities and velocities than would be predicted from locally derived compaction trends. Combinable magnetic resonance measurements indicate that the anomalous properties are the result of lower-than-expected capillary-bound microporosities. It is proposed that carbonic acid in the reservoir fluids diffuses into the bounding rocks, causing a loss of porosity. The amount of porosity lost depends on the clay content of the mudrock and the initial level of compaction, with shallower, more clay-rich shales able to lose more porosity. The anomalous seismic signatures result from a sharp transition (over approximately 5 m) at the diagenetic front between normal and altered rocks. The alteration can significantly change the amplitude variation with offset response of the reservoirs and therefore the ability to correctly predict fluid phase and reservoir quality. No anomalies are observed when the concentration of CO2 in the reservoir is less than 10% but always present when CO2 exceeds 20%. Therefore, it is possible to map the general distribution of high CO2 concentration from seismic data. There is no indication that the scale, amplitude, or shape of the anomalies gives an indication of the concentration of CO2.

Integration of petrophysical and geochemical approaches for lower Miocene Euphrates and Jeribe Formations in selected wells in Tawke Oil Field, Northwestern Iraq, Zagros-fold belt

The Lower Miocene Euphrates and Jeribe Formations are among Iraq's potential reservoirs with significant proven reserves. Petrophysical and geochemical techniques were used to investigate these Formations in the recently discovered Tawke Oil Field. Investigation consisted of acquiring a considerable amount of data from eight wells including conventional core analysis, wireline logging data, gas chromatography data and formation water analysis. The Euphrates and Jeribe Formations are considered to have low to moderate porosity (avg. 2.7–20.5%) and low matrix permeability (avg. 0.87–15mD). Secondary porosity is more prevalent than primary depositional porosity and is a significant factor in optimal reservoir properties with an average of 3.7–5.4% Secondary Porosity Index (SPI) for Jeribe and Euphrates Formations respectively. Meanwhile, fractures increased matrix permeability by up to 33mD and 56mD in the Euphrates and Jeribe Formations respectively. Lithology and core analysis revealed that the Dhiban Formation is a non-reservoir rock with maximum 2% He-Porosity and 0.069mD Klinkenberg permeability confirming that the formation is insufficient as a hydrocarbon reservoir, and that the rock properties are primarily controlled by the depositional environment. The Jeribe Formation contains crude oil of intermediate gravity and high sulfur content. According to gas chromatograph analysis the liquid and oil extracted from the Jeribe Formation originated from a matured marine setting that was possibly algae rich (Type-II kerogen) and has been deposited in a reductive environment. It is believed that these hydrocarbons were sourced from the Middle Jurassic Sargelu and Upper Jurassic-Lower Cretaceous Chia Gara Formations. The chloride-calcium water class is determined from the produced water in the Jeribe Formation and the concentration of elements with dissolved salts confirmed that the Jeribe Formation is in contact throughout eight Tawke wells studied.

LITHOFACIES DISTRIBUTION AND DEPOSITIONAL ARCHITECTURAL STUDIES OF THE MIOCENE DEPOSITS OF THE “THOR” FIELD, COASTAL SWAMP DEPOBELT, NIGER DELTA BASIN, NIGERIA

The study accesses the petrophysical data from the Eocene deposit of the “Thor” field, Coastal swamp depobelt, Niger Delta and process it to decipher the different lithological makeup, the reservoir units, the depositional architecture and how these factors influenced reservoir distribution within the field. The study made use of well logs consisting of gamma ray, resistivity, neutron and density logs. Gamma ray log aided lithological identification, resistivity logs help to isolate reservoir rocks from non-reservoir rocks while neutron and density logs was used to differentiate oil or gas zones. Three hydrocarbon reservoirs designated as R-1, R-2 and R-3 were interpreted from the logs and the sand bodies show a lateral continuity within the field in the north-eastern direction. Log sequences analysis of the field made use of a combination of gamma ray and restively logs via electro-sequence identification and mapping of key stratigraphic surfaces and the identification of para-sequences including retrogadational, aggradational and progradational stacking pattern leading to the delineation of the environment of deposition. The three stratigraphic surfaces enable the classification of the field into two depositional sequences and further subdivision into three system tracts. The first depositional sequence is interpreted as the oldest and lies at the base which is about 1201ft thick while the second depositional sequence overlies the first sequence with about 1605ft in thickness and is interpreted to be younger. Sediments within the two sequences are thought to be deposited in deltaic environment within the marginal to shallow marine settings.

The structure and role of faulting and fracturing system in spatial oil saturation of rocks and in occurrence of oil reservoirs within Chezhen sag of Jiyang depression in the Bohai Bay Basin in East China

The article reports the integrated analysis of the history, geodynamics, modern faulting system, internal structure and spatial occurrence of Paleozoic and Paleogene (Eocene) accumulations of oil in the promising Chezhen block of the Chezhen sag of the Jiyang depression in the Bohai Bay Basin in East China. After review of the new geological, geophysical and field studies, the authors find out that in this structurally complex system of faults and fractures of different age, orientation and types, the present-day spatial occurrence of oil reservoirs is governed by the neofaults which blanket the whole geological section, including the Paleozoic period. The studies (analysis of polished sections) into internal structure (micro fracturing) and oil saturation of rocks produce some new data of interest for the theory and practice. The studies of samples from the reservoir and non-reservoir rocks in exploration drilling in the Shahejie pay horizon show that oil saturation is connected with the presence of the younger age system of micro fractures (permeable) of horizontal and vertical (faults) orientation. The further exploration in the promising Chezhen block of the Shenli oil field is recommended to continue in the zones of the Cenozoic faults as any rocks (irrespective of their lithology, including low-porosity rocks) can be saturated with oil in these zones which contain the best-type reservoirs (fractured) and feature active fluid neodynamics.

Single or Multiple Porosity Cut Off A New Relevance Provided By Application of A New Approach

Porosity cut-off is one of the most important parameter normally used to differentiatebetween reservoir and non-reservoir rocks. Quantity of the parameter certainly dictatesreservoir volumes, hence directly influences economics and commerciality of a given oil/gas field. An ever critical issue in relation to this parameter is whether the use of porositycut-off has to be established through a single or multiple values especially for heterogeneousformation rocks. This certainly may lead to different reservoir sizes along with thetechnical and economical consequences. The study presented in this article is meant to furtherinvestigate this question. The thrust of this study lies on the application of a newlyproposed method for determining porosity cut-off. It is put that with this new and reliablemethod – compared to the traditionally used method – a more conclusive answer can beachieved. For the purpose, a heterogeneous limestone reservoir in West Java – Indonesiais used. Evaluation, analysis, and application of the new method on data from the field’seight wells have shown that multiple porosity cut-off values are needed for better definitionsof reservoirs. Application of a single value for these reservoirs can still be regardedas unrepresentative. The fact underlines that – despite the new approach’s reliability –heterogeneity governs more over the use of either single or multiple cut-off values ratherthan limitations of method. The study also proves that the new method for determiningporosity cut-off works well for highly heterogeneous reservoir rocks.

Geomechanics and electrofacies characterization of the Los Molles Formation (lower to Middle Jurassic), Neuquén Basin

Los Molles Formation (Lower to Middle Jurassic), deposited under the first marine event above the synrift continental deposits of the Precuyo, is the second most important source rock of the Neuquén Basin after Vaca Muerta Formation. Los Molles Formation extends over more than 45,000 km2 and can be recognized in different geographic areas within the basin.Los Molles Formation, with a thickness that varies from 100 to 800 m, has a total organic content (TOC) ranging from 1 to 5%, vitrinite reflectance (%Ro) 0.8 to 2, Hydrogen Index 300–500 mg HC/gTOC, SPI of 6 t HC/m2, kerogen type II-III and a VKA of algal amorphous with variable terrestrial contribution. In the studied area, the unit is subdivided into three members, with different characteristics that reflect distinctive sedimentary environments from shallow marine to deltaic.In addition to its condition of source rock, conventional and unconventional shale and tight reservoirs are currently being developed mainly within the vicinity of the depocenter of the basin, mostly related to gas prone basin centered gas systems. Volume estimation assigns 190 to 270 TCF of gas to this formation and 3.7 BBO.Outcrops, three cores and fifteen wells with open hole logs consist of the database for this study. Deductive methodologies were used to characterize the formation with standard log analysis that consist of differentiating reservoir to non-reservoir rocks, sandstones, silt, tuff, clay, porosity, water saturation, permeability, TOC, Young's modulus, Poisson's ratio and brittleness index. Inductive methodologies (clustering) were used for determining electrofacies that correspond to: Sp, sand, medium to very coarse, may be pebbly, solitary or grouped; Sh, sand very fine to very coarse, may be pebbly, horizontal lamination; Fm, mud, silt, massive; and Gm, massive or crudely bedded gravel, horizontal bedding, imbrication.The results of this study demonstrate the importance of taking advantage of different techniques when studying elements of the petroleum system related to Los Molles Formation.

Improved ST-FZI method for permeability estimation to include the impact of porosity type and lithology

Permeability represents the flow conductivity of a porous media. Since permeability is one of the most vital as well as the complex properties of a hydrocarbon reservoir, it is necessary to measure/estimate accurately, rapidly and inexpensively. Routine methods of permeability calculation are through core analysis and well tests, but due to problems and weaknesses of the aforementioned methods such as excessive costs and time, these are not necessarily applied on neither in all wells of a field nor in all reservoir intervals. Therefore, log-based approaches have been recently developed. The goal of this research is to provide a flowchart to estimate permeability using well logs in one of Iranian south oil fields and finally to introduce a new algorithm to estimate the permeability more accurately. Permeability is firstly estimated using artificial neural network (ANN) employing routine well logs and core data. Subsequently, it is estimated using Stoneley-Flow Zone Index (ST-FZI) and is compared with the results of core analysis. Correlation coefficients in permeability estimation by artificial neural network and Stoneley-FZI are R2 = 0.75 and R2 = 0.85, respectively. On the next step, an improved algorithm for permeability prediction (improved ST-FZI) is presented that includes the impact of lithology and porosity type. To improve the permeability estimation by ST-FZI method, electro-facies clustering based on MRGC method is employed. For this purpose, rock pore typing utilizing VDL and NDS synthetic logs is employed that considers the porosity types and texture. The VDL log separates interparticle porosity from moldic and intra-fossil porosities and washes out and weak rock-type zones. Employing MRGC method, three main facies are considered: good-quality reservoir rock, medium-quality reservoir rock and bad-quality (non-reservoir) rocks. Permeability is then estimated for each group employing ST-FZI method. The estimated permeability log by improved ST-FZI method shows better match with the measured permeability (R2 = 0.93). The average error between estimated and measured permeability for ANN, ST-FZI method and improved ST-FZI method is 1.83, 1.18 and 0.796, respectively. The increased correlation is mainly due to involving the impact of porosity types on improved ST-FZI method. Therefore, it is recommended to apply this algorithm on variety of complicated reservoir to analyze its accuracy on different environments.

Seismic Wave Propagation Simulation in a Poro-elastic Medium Using Spectral Method Elements in MPI-GPU Cluster: Study Case of Anticline Reservoir Trap

Modeling 2D seismic wave propagation using spectral element method on MPI-GPU clusters has been implemented and can complete the problem of elastic-poro elastic medium model. Free surface boundary conditions and absorption layer will use the CPML method. Seismic wave propagation simulation in hybrid elastic-poroelastic medium has been carried out on hydrocarbon reservoir models with anticline type. In reservoir rocks that have a poro elastic medium, there will be a fast and slow P wave. While in non-reservoir rocks that have elastic medium, only P fast waves is observed. The computation time for an anticline type reservoir model with dimensions of 1 km x 1.5 km using MPI 4 nodes cluster with 48 CPU cores is 3 minutes 48 second.

Depositional environment and reservoir characterization of the deep offshore Upper Miocene to Early Pliocene Agbada Formation, Niger delta, Nigeria

Recently, continued global demand for energy has necessitated more research for a better understanding of depositional environments and petrophysical parameters of reservoir sands in order to discover more petroleum accumulation. Therefore, the integration of lithological and well log data analyses of ditch-cutting samples from Wells A, B and C from the Niger Delta region are utilized to delineate the Upper Miocene and Early Pliocene Agbada Formation's depositional environments and to determine the quality of the delineated reservoir sands. The detailed well log analysis revealed two major electrofacies namely, shale and sand, while lithofacies analysis identified four facies, which are sandstone, siltstone, claystone and mudstone that were deposited in various depositional environments and sequences. Shale (claystone and mudstone) lithology is characterized by irregular and bell gamma-ray log motifs, which may be deposited in basin plain marine and transgressive marine shelf environments that are associated with transgressive depositional sequences. In contrast, sand (sandstone and siltstone) lithology is typified by funnel and cylindrical gamma-ray log motifs that are deposited in crevasse/prograding delta (sub-unit of fluvial/deltaic environment), and slope/inner fan channel and turbidite environments that are correlated to regressive and aggradation depositional sequences, respectively. Furthermore, sedimentology analysis evidenced twelve, four and seven reservoir sands in wells A, B and C, respectively, while qualitative analysis of well logs reveals eighteen (notated as A to R), four (A to D) and fifteen (A to P) reservoir sands in wells A, B and C, respectively. Moreover, palynological analysis shows alternation of transgressive and regressive sequences in wells A, B and C in this study. The prevalence of mangroves, spores, freshwater swamp and lowland rainforest pollen with rare occurrence of savanna pollen characterized the transgressive sequences, while low percentages of these assemblages with high occurrence of savanna pollen signified the regressive sequences in this study. Alternatively, quantitative analysis showed that volumes of shale (Vsh) are generally low and allow distinction of delineated reservoir sands into clean sand zones (<10% Vsh) and shaley sand zones (10–28% Vsh). Furthermore, water saturation (Sw) ranges from 13.0% to 63.0%, 5% to 27% and 37%–71% (wells A, B and C), and hydrocarbon saturation (Sh) ranges from 37.0% to 87.0%, 64%–95% and 29–63% in wells A, B and C, respectively. Estimated porosity values are relatively high and a porosity cutoff value of <30% permits to distinguish between reservoir and non-reservoir rocks. Furthermore, hydrocarbon saturation (37–87%) and permeability (10–50%) are relatively moderate to high and fair to moderate values, respectively. However, a strong linear relationship exists between permeability and porosity with positive coefficients of correlation that are ranging from near perfect to very significant in this study, and is an indication of permeable and porous sand facies. In conclusion, the economic importance of some of the delineated depositional environments and the outcome of reservoir characterization in this study has been previously highlighted in the Niger Delta Basin and other basins of the world. Therefore, the reconstruction of depositional environments and resulting petrophysical parameters in this study will help in understanding the geology of Agbada Formation, which will further enhance hydrocarbon exploration and exploitation in the Niger Delta region.

Technology Focus: Formation Evaluation (August 2017)

Technology Focus Not too long ago, horizontal drilling revolutionized the petroleum industry. Emerging logging-while-drilling and geosteering technologies helped bring about multilateral, maximum-contact, and smart-completion wells, allowing reservoirs to be developed and produced much more efficiently and economically. This increased recovery, thus boosting reserves. In the process, formation evaluation plays a critical role in determining whether a producer or an injector is successful. More recently, efficient mass horizontal drilling and optimized multistage massive fracturing have turned traditionally nonreservoir source rock into sweet spots of energy strategy on a global scale. Production from unconventional reservoirs in the last decade has dramatically changed the petroleum industry, and this movement continues to evolve. Developing unconventional resources demands unconventional thinking, mainly because of the many challenges involved in evaluating tight source rocks. The two fundamental petrophysical properties, pore structure and wettability, are completely different between conventional reservoirs and unconventional source rocks. What may be next on the horizon? It is estimated that methane hydrates contain much more gas than shale plays, and, understandably, many countries are keen to explore this vast potential. As per recent news releases, China Geological Survey geoscientists and China National Petroleum Corporation engineers may have made a great technology breakthrough by being able to test significant hydrate-gas production in the South China Sea. If this is sustainable, exploring hydrate gas may be the next game changer for the energy industry. Evaluating hydrate gas formations would not be easy, however, and producing them safely, economically, and in an environmentally friendly way would be very challenging. But, I have high hopes that future technologies will be able to resolve these challenges to produce hydrate gas conventionally so it can be used to improve living standards. Recommended additional reading at OnePetro: www.onepetro.org. SPE 182448 The Petrophysics Role of Low-Resistivity Pay Zone of Talang Akar Formation, South Sumatera Basin, Indonesia by Z. Holis, SKK Migas, et al. SPE 183883 Using Digital Rock Modeling To Estimate Permeability and Capillary Pressure From NMR and Geochemical Logs by Hao Zhang, Baker Hughes, et al. SPE 183800 An Innovative Approach for Integrated Characterization and Modeling of a Complex Carbonate Reservoir by F. Ben Amor, Schlumberger, et al.

Applying the evaluation results of porosity-permeability distribution characteristics based on hydraulic flow units (HFU) to improve the reliability in building a 3D geological model, GD field, Cuu Long Basin

Constructing a facies model in geological modeling with two types of rock facies is not only stimulating but also necessary for modeling in a new direction to be able to reflect the interconnection of the oil body as well as heterogeneity of reservoir characteristics more clearly. The results of environmental interpretation derived from core sample data show that more than ten kinds of facies in rivers/lakes have been identified in the study area. However, predicting this kind of facies in the space of coring in wells and then simulated reservoirs as depositional facies faces many difficulties. Therefore, the simulation under lithology facies still includes reservoir and non-reservoir rocks but splits reservoir rocks into different HU types based on their porosity-permeability characteristics derived from core analysis results used in facies modeling steps. FZI values are shown on the chart by the statistical probability of reservoir rock in four HU types corresponding to four lines with different slope angles representing each HU type from the core analysis data. The newly identified HU types then are shown on the Amaefule chart plot according to the relationships between the reservoir rock quality index and normalized porosity (Φz) for all core samples. The division of rock facies into HU types also refers to the results of sedimentary environmental interpretation from core sample data in the wells. We used the artificial neutron network method in the IP software to predict the FZI values and then grouped them by HU type for no core sample intervals of whole sections of the wells. Based on the facies model and parameter model of porosity, saturation was built, and in-place oil reserves were calculated using the volumetric calculation function in Petrel software. One hundred realizations were run, and we chose the base case corresponding to the P50 probabilistic results to simplify its use in production simulation models. Compared with the results calculated by volumetric methods for block H1 and H2 of 102 million barrels, those of oil-in-place reserves calculated from the model were more than about 3%.

Role of facies diversity and cyclicity on the reservoir quality of the mid-Cretaceous Mishrif Formation in the southern Mesopotamian Basin, Iraq

Abstract An integrated sedimentological and petrophysical approach was implemented to define the role of facies diversity and cyclicity on the reservoir quality of the Mishrif Formation in several oil fields in southern Iraq. The reservoir quality in most regressive cycles was enhanced upwards from deep-marine facies towards the shallower shelf-margin facies. The change in reservoir quality could be detected in the facies stacked systematically within the regressive cycles, which was also easily recognized using the porosity logs. The impact of early diagenetic overprints was quite obvious in developing both reservoir and non-reservoir rock types within the Mishrif Formation in the study area. A simple rock-typing nomenclature was proposed based on the available data in order to classify the existing reservoir (R) and non-reservoir (S) rock types. The best-recognized reservoir rock types were rudistid microfacies with grain-dominated fabrics (including both grainstone (R1) and grain-dominated packstone (R2)), which were subjected to an early diagenetic dissolution process, usually located beneath discontinuity surfaces. Such reservoir units or rock types have a regional extent within the southern Mesopotamian Basin, as they have often developed during the Mishrif shelf-margin progradation. In addition, the other important reservoir rock type was a microbialite (i.e. peloidal mud-dominated packstone (R3)), which was additionally characterized by micropores within the mud-dominated portion of the facies. However, owing to the variable intensity of the diagenetic effects and differences in the depositional texture components, the reservoir quality in this rock type could vary regionally. The regional distribution of the rudistid grainstone and grain-dominated packstone reservoir rock types (R1 and R2) was mostly related to the palaeogeographical highs that existed during deposition. However, such reservoir rock types could pinch out within the depositional sequences, showing their potential to become stratigraphic traps outside the structural crest of the field. The delineation of the reservoir rock types within a sequence-stratigraphic framework can be quite beneficial for reservoir prediction and exploration within and outside of the field.

Primary composition and diagenetic patterns of sandstones from Barra de Itiúba Formation in Atalaia High, Sergipe Sub-Basin

The petrologic analyses of 40 thin sections from two wells located in Atalaia High, offshore of Sergipe Sub-Basin, allowed the identification of primary composition and diagenetic patterns of Barra de Itiuba Formation. The original detrital compositions included arkoses, sublithic, and lithic sandstones. The main diagenetic processes observed were: compaction of metamorphic rock fragments and mud intraclasts, generating pseudomatrix; precipitation of quartz and feldspar overgrowths and outgrowths, cementation and grain replacement by kaolinite; dolomite and ferrous dolomite/ankerite; pyrite; iron oxides and hydroxides; and diagenetic titanium minerals, in addition to dissolution phases during eo-, meso- and telogenesis. The macroporosity in the two studied wells is primary intergranular, but there is secondary porosity due to dissolution of primary and diagenetic constituents, as well as fracture porosity. Thirteen reservoir petrofacies were defined and grouped into four reservoir petrofacies associations. They reflect the reservoir quality in microscale: good, medium and low-quality and non-reservoir. The good-quality is characterized by average total porosity greater than 15%, whereas the medium shows average total porosity greater than 7%. Low-quality presents average total porosity between 1 and 4%, and the non-reservoir has an average total porosity consistently less than 1%. Overall, the studied reservoirs consist on low-quality and non-reservoir rocks, which are intercalated with levels of medium- and good-quality. The loss of original porosity was mainly due to mechanical compaction (generating pseudomatrix), and cementation by kaolinite and dolomite. Preservation of primary porosity was favored by the presence of quartz overgrowths.

Appraisal of intra-reservoir barriers in the Permo-Triassic successions of the Central Persian Gulf

Owing to their tightness, intra reservoir barriers have the potential to prevent homogenization of reservoir fluids and so cause compartmentalization. Identification of these barriers is an important step during reservoir evaluation. In order to achieve this, three main approaches: i) detailed petrographic and core analysis, ii) petrophysical studies (flow unit concept) and iii) geochemical analysis (strontium residual salt analysis) were applied systematically in the Permo-Triassic carbonate reservoirs (Dalan and Kangan formations) of a supergiant gas reservoir located in the Central Persian Gulf. Integration of these approaches has led to a fullclarification of the intra reservoir barriers. Petrographic examinations revealed the potential stratigraphic barriers to fluids flow created by various depositional/ diagenetic characteristics. Petrophysical data such as poroperm values, pore throat size distribution and scanning electron microscopy (SEM) analysis were used to differentiate the reservoir flow units from non-reservoir rock. According to different trends in 87Sr/86Sr ratios of residual salts, the existence of flow barriers was evaluated and proved. Finally, by integrating these approaches, three intra reservoir barriers were introduced in the studied reservoir interval. These intra reservoir barriers are depositional and diagenetic in nature and are located in stratal positions with sequence stratigraphic significance. The possibility of reservoir compartmentalization was evaluated in the studied wells, and then their existence was predicted at the adjacent fields. As shown in this study, integration of petrographic examinations with flow unit determination in a sequence stratigraphic framework has the potential for recognizing intra reservoir barriers and predicting compartmentalization of the studied Permo-Triassic reservoirs.

Using formation micro-imaging, wireline logs and onshore analogues to distinguish volcanic lithofacies in boreholes: examples from Palaeogene successions in the Faroe–Shetland Basin, NE Atlantic

Abstract Formation micro-imaging (FMI) is a tool that produces micro-resistivity images of the sidewall of the well bore. FMI logging used in conjunction with conventional well logging techniques (e.g. GR, Gamma Ray/RES, Resistivity/NPHI, Neutron Porosity/SONIC, Velocity tools) allows detailed analysis of volcanic lithofacies variation and informs a robust interpretation of volcanic sequences. This methodology is of particular use where rock core data are limited or not present. Examples are presented from the Rosebank Field in the Faroe–Shetland Basin (West of Shetland, UK continental shelf) where the re-establishment of fluvial activity between phases of effusive volcanism resulted in a complex sequence of siliciclastic sedimentary rocks and basaltic lavas. We demonstrate how high-resolution FMI images through this sequence can differentiate internal basalt lava flow features, such as vesicular zones, brecciated intervals, sediment–lava contact relationships and joint/fracture networks. If FMI data exist through volcanic packages and if assessed and calibrated properly via core, sidewall core and field analogue comparisons, it can provide additional constraints on the interpretation and classification of reservoir (siliciclastic) and non-reservoir (volcanic) rocks.

Biogenically enhanced reservoir properties in the Medicine Hat gas field, Alberta, Canada

Spot-minipermeametry and micro-CT analytical techniques were employed to evaluate the effect(s) of bioturbation on porosity and permeability distributions in reservoir facies of the highly prolific Medicine Hat gas field of Alberta, Canada. This study focuses on five cm-scale samples that occur at different stratigraphic positions and intersect discrete bioturbated horizons within the Medicine Hat Member. Spot-minipermeability results demonstrate that permeability in bioturbated sandstones is up to two orders of magnitude greater than those of the muddy matrix, thus corresponding to a dual-porosity fluid flow system. Graphing bioturbation intensity versus measured permeability indicates that burrows are well connected horizontally and provide flow conduits. Micro-CT models reveal that burrowed sandstones are isolated and planiform in character; rare interpenetrations from vertically oriented trace fossils serve to interconnect these hydraulically isolated strata. Results show that bioturbated sandstones possess reservoir properties comparable to those associated with laminated sandstones, yielding an anisotropic porous medium. Understanding the impact of trace fossils on porosity–permeability distributions in the Medicine Hat gas field can be used to identify potential reservoir from previously interpreted non-reservoir rock, and, ultimately, improve reserve estimations.

Silvereye 1 Case Study – the False Positive

The objective of the recent Silvereye 1 exploration well in Bass Basin was to test Paleocene and Cretaceous sandstone reservoirs of the Eastern View Coal Measures (EVCM). The well was designed to test a faulted four-way dip closure and stratigraphic trap interpreted as a sand filled channel. Pre-drill analysis relied on a recent 3D marine seismic survey with well control provided by 2D seismic ties to wells located in adjacent exploration permits. The pre-drill interpretation of a gas-bearing sandstone-filled channel was based on a brightening of seismic amplitude (a predominantly class 3 AVO anomaly) associated with the channel feature. The AVO behaviour was consistent with the response at the same gas-bearing stratigraphic level in the nearby White Ibis 1 well, hence the presence of hydrocarbons (gas) was considered likely. The well intersected the predicted stratigraphy but failed to encounter hydrocarbons at any of the reservoir intervals. A channel sand was intersected within a thick claystone interval at the pre-drill proposed stratigraphic trap. The claystone is characterised by low-velocity and high density, while the sandstone has slightly higher porosity than sand typically encountered in this section. It was the contrasting characteristics of these lithologies that determined the class 3 AVO response and the misinterpretation of the anomaly. We show that a close examination of the rock physics trends of reservoir and non-reservoir rocks in surrounding wells could have allowed this scenario to be recognised pre-drill. Failure to recognise all possible lithological characteristics in the pre-drill AVO model meant that not all outcomes were analysed, and hence were not included in the risking of the prospect . The post drill evaluation has recognised that rock physics studies are an important tool for recognising all possible scenarios to aid in prospect evaluation. Had a more comprehensive rock physics evaluation been conducted, the actual outcome would likely have been recognised as one of several possibilities, but would not necessarily have prevented drilling of the well.

Computer modeling bioturbation: The creation of porous and permeable fluid-flow pathways

Computer modeling of trace fossils (Skolithos, Thalassinoides, Planolites, Zoophycos, and Phycosiphon) and ichnofacies (Skolithos, Cruziana, and Zoophycos ichnofacies) is undertaken to assess the impact of bioturbation on porosity and permeability trends in sedimentary media. Model volumes are randomly populated with the digitally modeled trace fossils to test for connectivity between burrows. The probability of vertical and lateral interconnections is compared with bioturbation intensity. The results of the simulations indicate that biogenic flow networks develop at low bioturbation intensity, between 10 and 27.5% bioturbation (BI-2). However, the efficiency of connectivity is controlled by the architecture of the burrows. For all trace-fossil and ichnofacies models, regardless of trace-fossil orientation, continuous horizontal and vertical connectivity across the sediment volume is achieved within a 0 to 10% range in bioturbation. In subsurface aquifers and petroleum reservoirs, the presence of bioturbation can significantly influence fluid flow. In particular, for marine sedimentary rocks, where burrows are more permeable than the surrounding matrix, a greater degree of three-dimensional burrow connectivity can produce preferred fluid-flow pathways through the rock. Recognizing these flow conduits may enable optimization of resource exploitation or may contribute to increasing reserve estimates from previously interpreted nonreservoir rock.

Net Pay: What Is It? What Does It Do? How Do We Quantify It? How Do We Use It?

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123561, ’Net Pay: What Is It? What Does It Do? How Do We Quantify It? How Do We Use It?’ by Paul F. Worthington, SPE, Gaffney, Cline &amp; Associates, prepared for the 2009 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 4-6 August. The paper has not been peer reviewed. Knowledge of net pay is important in the volumetric estimation of hydrocarbon resources, a practice that underpins the value of the petroleum industry. Yet, there is no universal definition of net pay. Net/gross pay constitutes a major source of uncertainty in volumetric resources estimates, second only to gross rock volume. A defensible rationale to guide the quantification of net pay (thickness) is presented. Central to this process is the identification of net-pay cutoffs. Introduction Net pay is a key parameter in reservoir evaluation. It identifies penetrated geological sections that have sufficient reservoir quality and interstitial hydrocarbon volume to function as producing intervals. It contributes to estimating a meaningful in-place volume against which recovery efficiency can be assessed usefully. Thus, net pay is central to the static-volumetric method of estimating ultimate recovery. Moreover, it facilitates reservoir simulation, because nonreservoir rock does not need to be characterized for inclusion. The full-length paper details methods of quantifying net pay by use of formation properties, and it promotes a method with fewer drawbacks. These matters are especially important during the early stages of field life, when uncertainty in estimated petroleum resources is greatest. Formation Thicknesses The total thickness of an evaluation interval, either along hole or in true vertical space, is termed “gross thickness.” The term “net thickness” indicates that some of the gross thickness has been removed. There are three types of net thickness: net sand, net reservoir, and net pay. Their interrelationship is summarized in Fig. 1. Net pay is a subinterval of net reservoir, which is, in turn, a subinterval of net sand. These thicknesses are used along hole for completions purposes and in true vertical space for volumetric computations. This classical terminology is rooted in the onshore oil industry. Although its use is widespread, it is inexact. Net sand would be described better as “net potential reservoir,” a term that encompasses, for example, carbonates and fractured basement. Net-reservoir intervals contain rocks that are identified as having a useful capability to store fluids and allow them to flow. In this respect, the term static volumetrics is potentially misleading. Net pay is a descriptor that originates in single-well completions onshore, where technical and economic decisions are contemporaneous. Where economic decisions are made on a field scale, a better term might be “net hydrocarbons.” In terms of the adopted convention, the ratio of net-to-gross thickness takes three forms: net/gross sand, net/gross reservoir, and net/gross pay. It is not appropriate to use the term “net/gross” without qualifying what it is.

The Application of Cutoffs in Integrated Reservoir Studies

Summary Methodologies have been developed for applying net reservoir and thence net pay cutoffs in cases of primary and waterflood depletion. The cutoffs are dynamically-conditioned to be reservoir-specific (i.e., they are tied back to a reference permeability parameter in a way that is driven by the reservoir data themselves). They also honor scale, where feasible, and are conformable with any pertinent rock-typing. For primary depletion, the Leverett equivalent circular pore diameter has been used to distinguish between reservoir and nonreservoir rock. This composite parameter can incorporate mobility for multiphase work. It is linked to a discrete core porosity under simulated reservoir conditions, so the adopted net reservoir cutoff is expressed as a limiting porosity. For waterflood depletion, an extrapolated endpoint relative permeability to oil has proved effective for the same purpose. Here, the zero endpoint relative permeability is linked to a conventional "absolute" core permeability corrected to reservoir conditions. Porosity is tied back to this limiting absolute permeability so that the net reservoir cutoff is again expressed in terms of porosity. Consequently, in both cases, the discrete porosity cutoffs have a dynamic significance. Other cutoff parameters, such as shale volume fraction and water saturation, can be tied back to these. A proposed workflow for applying dynamically-conditioned cutoffs allows data character to drive their use in integrated reservoir studies. The workflow constitutes a basis for greater technical consistency in the estimation of ultimate hydrocarbon recovery. However, the treatment is not exclusive, and other approaches to the determination of net pay will emerge as more reservoirs are considered.