Hydrocarbon Volumes Research Articles

Broadband Seismic: Ultimate Input for Quantitative Seismic Interpretation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150821, ’Broadband Seismic: The Ultimate Input for Quantitative Seismic Interpretation,’ by Cyrille Reiser, Euan Anderson, and Yermek Balabekov, Petroleum Geo-Services, prepared for the 2012 SPE North Africa Technical Conference and Exhibition, Cairo, 20-22 February. The paper has not been peer reviewed. Predicting reservoir properties away from the well using seismic information is key to quantitative interpretation. Quantitative seismic interpretation combines well and seismic data with seismic interpretation or early geological information. This proposed workflow is integrated, and the quality and accuracy of individual constituents are highly important to estimate the volume of hydrocarbon in place in a particular reservoir interval accurately. If seismic data contain very strong low-frequency information and the seismic image is of high quality/resolution, it is possible to estimate the absolute impedance directly at each point within a seismic volume. Introduction The ultimate goal in finding the best places to drill exploration or production wells is to characterize the physical properties of rock formations before drilling. Ideally, it would be desirable to have quantitative information regarding key rock properties (e.g., lithology, porosity, clay content, and net-/gross-pay ratio) along with information regarding fluid types, saturations, and pore pressures of potential reservoirs. Historically, seismic images have not delivered this information because the seismic bandwidth was limited by the conventional- streamer design and acquisition method. The conventional-streamer acquisition with a single type of sensor (hydrophone) and conventional towing depth fails, in most cases, to fulfill the geoscientist requirement. Therefore, broader bandwidth is needed with as much low- and high- frequency extension as possible. There is an urgent need to characterize very complex reservoirs accurately and be able to resolve very thin remaining hydrocarbon columns. To achieve an improved seismic characterization of the reservoir and better reservoir- property prediction away from the well, high-quality broadband seismic is needed. Well data offer high vertical resolution but do not provide lateral information, whereas seismic data have densely spaced traces with limited vertical resolution. Quantitative interpretation, or seismic reservoir characterization, is a work-flow that combines well and seismic data with seismic interpretation or early geological information. This workflow is highly integrated, and the quality and accuracy of individual constituents are of great importance to develop an accurate estimate of the hydrocarbon-in-place volume in a particular reservoir interval with the main aim being to optimize the drilling location on the basis of 3D seismics. Data Acquisition New acquisition methods and technologies have been introduced to provide a broader seismic bandwidth. Advances include variable inline-streamer towing depth, acquisition with streamers at different constant depths, and dual-sensor towed streamer. The dual-sensor (combination hydrophone and vertical-velocity sensor) towed streamer enables effective removal of the sea-surface ghost by use of wavefield separation, allowing capture of the full bandwidth of the upcoming wavefield.

Assessing the impact of hydrocarbon leakages on vegetation using reflectance spectroscopy

This paper assesses the capability of hyperspectral remote sensing to detect hydrocarbon leakages in pipelines using vegetation status as an indicator of contamination. A field experiment in real scale and in tropical weather was conducted in which Brachiaria brizantha H.S. pasture plants were grown over soils contaminated with small volumes of liquid hydrocarbons (HCs). The contaminations involved volumes of hydrocarbons that ranged between 2L and 12.7L of gasoline and diesel per m3 of soil, which were applied to the crop parcels over the course of 30days. The leaf and canopy reflectance spectra of contaminated and control plants were acquired within 350–2500nm wavelengths. The leaf and canopy reflectance spectra were mathematically transformed by means of first derivative (FD) and continuum removal (CR) techniques. Using principal component analysis (PCA), the spectral measurements could be grouped into either two or three contamination groups. Wavelengths in the red edge were found to contain the largest spectral differences between plants at distinct, evolving contamination stages. Wavelengths centred on water absorption bands were also important to differentiating contaminated from healthy plants. The red edge position of contaminated plants, calculated on the basis of FD spectra, shifted substantially to shorter wavelengths with increasing contamination, whereas non-contaminated plants displayed a red shift (in leaf spectra) or small blue shift (in canopy spectra). At leaf scale, contaminated plants were differentiated from healthy plants between 550–750nm, 1380–1550nm, 1850–2000nm and 2006–2196nm. At canopy scale, differences were substantial between 470–518nm, 550–750nm, 910–1081nm, 1116–1284nm, 1736–1786nm, 2006–2196nm and 2222–2378nm. The results of this study suggests that remote sensing of B. brizantha H.S. at both leaf and canopy scales can be used as an indicator of gasoline and diesel contaminations for the detection of small leakages in pipelines.

Technology Focus: Well Testing (February 2013)

Technology Focus The times they are a-changin’, Bob Dylan sang in the mid-1960s. And it seems to be the case in our industry today. With the never-ending search for new sources of hydrocarbons in more-complex environments, the application of old technologies has not been satisfactory to help us fully realize the new exploration opportunities. As the oil industry endeavors to extract hydrocarbons from fields where, only a few decades ago, it seemed impossible, engineers and scientists are tasked with developing ideas to gain an understanding of the dynamic behavior of the reservoirs, sometimes requiring redundant information. Creativity and ingenuity are called upon when facing challenging projects. Both are particularly necessary when one is trying to extract as much information as possible by the clever integration of multiple groups within an organization and manipulation of complementary data sets. Despite the difficulties encountered in unconventional plays or in tight carbonates that normally require stimulation, along with patience and long-term commitment, the application of sound engineering principles has opened new areas around the world that, until recently, were perceived as not being economical. Two of the key parameters required for full exploitation of a hydrocarbon-bearing field—rock permeability and reservoir pressure—are probably the most elusive to determine in the exploration phase, particularly so in unconventional plays. Hence, any technique that decreases the uncertainty in those estimates is a new valuable tool to the engineers involved in the exploration of new frontiers. Once the size and properties of the container have been evaluated, knowledge of the fluid properties is required to under-stand the flow characteristics. In the early stages of developing a field, on the other hand, engineers and geoscientists continue to integrate as many data sets as possible to quantify the volume of hydrocarbons that may be produced. The well-test data, however, confirm whether the hydrocarbons are producible. With this information, field development can start in earnest. The integration of the static and dynamic data then provides encouragement to develop a field. The three articles chosen are good examples of data integration to understand a field or the clever use of well-test data to solve a specific problem. The interested reader should also check the three alternative articles, as well as other articles available in the OnePetro library (www.onepetro.org). Recommended additional reading at OnePetro: www.onepetro.org. SPE 159126 Reservoir-Connectivity Analysis Using Long-Term Interference Testing in a Waterflood Pilot in the Carbonate Marrat Formation of the Greater Burgan Field, Kuwait by Naz Gazi, Kuwait Oil Company, et al. SPE 159503 Sampling While Drilling: An Emerging Technology by Steven Villareal, Schlumberger, et al. SPE 159680 Investigation of Thermal Well-Test Analysis for Horizontal Wells in SAGD Process by Ashkan Jahanbani Ghahfarokhi, Norwegian University of Science and Technology, et al.

Legal Issues and Scientific Constraints in the Environmental Assessment of the Deepwater Horizon Oil Spill in Mexico Exclusive Economic Zone (EEZ) in the Gulf of Mexico

The largest accidental marine oil spill (4.9 million barrels) in the Gulf of Mexico (GoM) seabed (1600 m) caused by the sinking of the Deepwater Horizon oil rig in 2010, put to the test once again the resilient capacity of the pelagic and benthic realms of this Large Marine Ecosystem. Many are the ecological services provided by its waters (fisheries, tourism, aquaculture and fossil fuel reserves) to neighboring countries (US, Mexico and Cuba). However, the unprecedented volumes of hydrocarbons, gas and chemical dispersants (Corexit) introduced in the system, represent ecological stressors whose deleterious effects are still the subject of civil claims and scientific controversy. Presumably, the short scale effects were confined to the Gulf’s northeastern shallow waters, and the combined actions of weathering, biodegradation, and oil recovery left the system almost under pre-spill conditions. Unfortunately, surface and subsurface oil plumes were detected in the spill aftermath, and their dispersion trajectories threatened Mexico EEZ. Surface oil slicks were detected in the pristine waters of northern Yucatan, while subsurface oil plumes from the Macondo’s well blowout were dangerously advancing southwest towards key fishing grounds in the northwestern GoM. This disaster prompted the Mexican government to implement an ambitious ocean monitoring program adopting a bottom-up approach focused on building a base line for more than 42 physicochemical and biological variables for water, sediment and biota from the continental shelf-slope region of the NW GoM. Technological constraints have precluded systematic observations in the vast Mexican EEZ that could discriminate natural variability and oil seep emissions from antropic disturbances. Therefore, preliminary risk analyses relied on seasonal and historical records. Two years of field observations revealed subtle environmental changes in the studied area attributed to antropic disturbances. Waters maintained oligotrophic conditions and zooplankton and benthic infaunal biomass were also poor. Biomarkers in sediments and biota did not exceed EPA’s benchmarks, and sediment’s fingerprinting (δ13C) indicated marine carbon sources. Geomarkers revealed an active transport from the Mississippi towards the NW GoM of phyllosilicates bearing a weathered oil coating. Consequently, shelf and slope sediment toxicity begins to show an increasing trend in the region. The complexity of hydrocarbons bioaccumulation and biodegradation processes in deep waters of the GoM seems to indicate that meso-and large-scale observations may prove to be essential in understanding the capacity of the GoM to recover its ecological stability.

A multicomponent seismic framework for estimating reservoir oil volume

Defining the volume of hydrocarbons in a reservoir is a key aspect of resource estimation. Subsequently, determining the likelihood of this volume is critical for reserve evaluation. We outline a geophysical framework using multicomponent (3C) 3D seismic data, well logs, and geostatistics to assist in this assessment. The use of converted-waves (P-to-S) is a significant and integral part of the process, especially in estimating the reservoir sand thickness and its porosity. This procedure is applied to data from the Blackfoot oil field, Alberta. The predicted original oil in place and its likelihood (90% probability of 4.5 MMbbl computed from 1996 geophysical data) compares reasonably well with that inferred from actual cumulative production up to 2011 (5.5 MMbbl)

Controls on the deposition and preservation of the Cretaceous Mowry Shale and Frontier Formation and equivalents, Rocky Mountain region, Colorado, Utah, and Wyoming

Regional variations in thickness and facies of clastic sediments are controlled by geographic location within a foreland basin. Preservation of facies is dependent on the original accommodation space available during deposition and ultimately by tectonic modification of the foreland in its postthrusting stages. The preservation of facies within the foreland basin and during the modification stage affects the kinds of hydrocarbon reservoirs that are present. This is the case for the Cretaceous Mowry Shale and Frontier Formation and equivalent strata in the Rocky Mountain region of Colorado, Utah, and Wyoming. Biostratigraphically constrained isopach maps of three intervals within these formations provide a control on eustatic variations in sea level, which allow depositional patterns across dip and along strike to be interpreted in terms of relationship to thrust progression and depositional topography. The most highly subsiding parts of the Rocky Mountain foreland basin, near the fold and thrust belt to the west, typically contain a low number of coarse-grained sandstone channels but limited sandstone reservoirs. However, where subsidence is greater than sediment supply, the foredeep contains stacked deltaic sandstones, coal, and preserved transgressive marine shales in mainly conformable successions. The main exploration play in this area is currently coalbed gas, but the enhanced coal thickness combined with a Mowry marine shale source rock indicates that a low-permeability, basin-centered play may exist somewhere along strike in a deep part of the basin. In the slower subsiding parts of the foreland basin, marginal marine and fluvial sandstones are amalgamated and compartmentalized by unconformities, providing conditions for the development of stratigraphic and combination traps, especially in areas of repeated reactivation. Areas of medium accommodation in the most distal parts of the foreland contain isolated marginal marine shoreface and deltaic sandstones that were deposited at or near sea level lowstand and were reworked landward by ravinement and longshore currents by storms creating stratigraphic or combination traps enclosed with marine shale seals. Paleogeographic reconstructions are used to show exploration fairways of the different play types present in the Laramide-modified, Cretaceous foreland basin. Existing oil and gas fields from these plays show a relatively consistent volume of hydrocarbons, which results from the partitioning of facies within the different parts of the foreland basin.

Fluid- and Rock-Property Effects on Reserves Estimation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed. Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted. Introduction Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure. Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods. Model Description The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.

Definitive Petrophysical Evaluation of Thin Hydrocarbon Reservoir Sequences

SummaryThe petrophysical evaluation of thinly-bedded sand/shale sequences is strongly dependent on the way in which layered and dispersed shales are taken into account. There are two underpinning issues: the recognition of thin bed geometries and the estimation of shale content from lithology logs. The first of these is managed through a scenario approach, whereby different downhole scenarios are set out according to specified ranges of bed thickness. Each range has its own interpretation protocol. The second issue relates to the inherent overestimation of clay-mineral volume fraction by shale indicators and its impact on the petrophysical evaluation of thinly-bedded sand porosity. This shortcoming is managed by applying a validated scaling factor to log-derived estimates of shale volume fraction so that these become workable estimates of clay-mineral fraction for the porosity evaluation of sand layers. Both these problems become more acute for thinner beds. These two key issues are addressed conjunctively through interpretive workflows, each of which relates to a discrete range of bed thickness and uses fit-for-purpose petrophysical data sets. In particular, the multicomponent induction log is adopted as a pivotal technology for the evaluation of sand resistivity within thinly-bedded sand/shale sequences. The objective is to achieve a sound petrophysical interpretation for each downhole situation. Therefore, groundtruthing through core data is advocated where this allows the shale problem to be managed better. The outcome is a systematic approach to thin-bed evaluation, based on prescribed data inputs that optimize project effectiveness. The benefits are illustrated through case histories that demonstrate a securable upside in projected hydrocarbon volumes.

Innovation: Innovation in Our Industry

President's column In spite of persistent global economic turmoil, various sources predict that the world will continue to need increasing volumes of hydrocarbons to support a growing population and to improve the standard of living in areas where standards are currently low. Therefore, our industry will need to continue to find and produce hydrocarbons from additional resources in increasingly complex regions and geological settings. This will make the activities in our industry more difficult and expensive and will present new challenges that will call for innovative solutions. There is a general and well grounded belief that we still have many opportunities, in both green and brown fields. The challenge is how to bring production from these fields to the market in a manner that is cost-effective, safe, environmentally and host-community friendly, using mature and well tested techniques, equipment, and processes while we explore innovative ways to continuously improve our methods. We live in a world where the pressure on resources will demand that smaller and smaller amounts of materials and efforts will accomplish more and more, thus achieving “ephemeralization,” (Fuller, 1938) a word that Buckminster Fuller, an American inventor, used to describe progressively accomplishing more with less. This pressure, among other factors, has driven innovation in our industry. I will examine some of the game changers that have shaped our industry in the last 10 to 20 years in my JPT columns in the coming months. Innovation has always played a very important role in our industry, but some-times I wonder if we under-estimate this role. Does constant contact with what we have today make us forget that such techniques were not always there and that some innovative mind brought about the new ways we now enjoy? Think about 3D seismic, deepwater drilling, horizontal drilling, some of the very sophisticated logging tools now in use, and reservoir characterization, to name only a few. The one sector outside our industry that has had a tremendous innovative impact is information technology—the effects of IT’s growth, new products, and adaptions introduced in the last 10 years has been phenomenal. How does innovation come about? What is it that makes a few of us use the huge fertility of our mind to challenge the known and seek better ways? A number of groups have studied this phenomenon and come up with what really drives innovation. I recently came across a study carried out by New & Improved, a global organizational development firm, which identified 10 things that really drive innovation (New & Improved LLC. 2010). I have chosen to focus on the top two things: the individual and the team. I believe these are the main drivers of change in our industry.

Assessing continuous resources - building the bridge between static and dynamic analyses

Abstract The processes associated with assessing conventional hydrocarbon accumulations are well understood and routinely applied. These assessments can have either a local (prospect) or regional (play) focus, depending on the business need, and rely on risking, sizing, and counting discrete prospects. In contrast, many continuous resource plays are better characterized as a single large hydrocarbon accumulation with highly variable resource density rather than as discrete fields or prospects. Because economic margins may be thin, business success often depends on early identification of favorable areas. Decisions regarding play entry, acreage acquisition, and pilot project design frequently must be made without the benefit of recent well or production data. The assessment methodology for continuous resources must be flexible enough to adapt to situations ranging from little or no well data to thousands of wells. Play assessment provides a powerful mechanism for integrating geologic insights into business decisions. To incorporate the unique aspects of continuous resources, we apply a hybrid grid and polygon based methodology. The play is subdivided into a series of analysis polygons (subplays or segments) that provide the basis for probabilistic calculations. The polygon boundaries can be dynamic (mapped geologic limits), static (leases), arbitrary, or some combination of these. Polygons should be defined for the purpose at hand and at a granularity that captures but does not overwhelm regional trends. Those geologic properties mapped spatially as grids (e.g. gross thickness, net-to-gross, or porosity) are evaluated within each analysis polygon to obtain inputs for the probabilistic assessment. Geologic properties that are not available as spatially varying estimates can be assigned directly with appropriate ranges of uncertainty. Resource uncertainty can be captured both as ranges around most likely parameter estimates and as multiple geologic or operational scenarios. Risk dependency and volumetric correlation must be defined in order to obtain robust probabilistic aggregations of multiple analysis polygons. Fully probabilistic results lead to better informed business decisions by providing information on high side and low side outcomes. Concurrent with the probabilistic assessment, deterministic grid-based calculations of in-place and recoverable hydrocarbon volume per unit area elucidate the resolvable geographic variation of resource density. The parallel grid-based approach ensures that results incorporate and are consistent with local geologic understanding and provides a direct basis for calibrating volumetric calculations with well performance data. Ultimately, assessments based on well performance provide the clearest indication of the recoverable resource and economic viability of a play. Unfortunately, well performance-based approaches are not reliable until a high operational efficiency has been achieved and the number of wells with adequate production histories is sufficient to clarify the primary controls on resource density. To provide early prediction of well performance within the context of volumetric assessment, probabilistic ranges of well EURs are estimated for each assessment polygon based on volumetric inputs coupled with assumptions about likely drainage areas. Well drainage area can be entered as a single value or as a range tied to reservoir properties (permeability and rock mechanics), geologic complexity (faulting), and completion scenarios (well spacing, vertical vs. lateral completions, length of laterals, etc.). As performance-based EUR projections become available for wells, they can be compared to the specific recoverable volume prediction from the resource density grid along with the distribution of well EURs predicted for the polygon. Population-based Bayesian statistical techniques provide robust, probabilistic predictions of EUR for producing wells within a play. Combining analog datasets of initial potential (IP) with well EUR provides a dynamic linkage of the volumetric assessment to well performance. Applying relationships between EUR and IP from analog plays to EUR curves (one per polygon) for the play of interest yields spatially varying families (distributions) of IP’s. By recasting assessed volumes in terms of well productivity, this process supports economic analyses explicitly linked to spatially varying geologic inputs.

Effect of monomer and hydrocarbon content and polarity of the medium on the preparation of nonspherical particles via seeded dispersion polymerization in the presence of saturated hydrocarbon droplets

In this work, the preparation of micron-sized polymer particles with nonspherical shapes via seeded dispersion polymerization of 2-ethylhexyl methacrylate (EHMA) with polystyrene (PS) seed particles in the presence of decane droplets and evaporation of decane after the polymerization under various polymerization conditions was discussed. The effect of monomer and decane content and polarity of the medium on the shape of the obtained particles was investigated. The experimental results showed that decreasing the amount of monomer and hydrocarbon volume of PEHMA/hydrocarbon domains, the particles decreased but they grew symmetrically, resulting in symmetric shapes. Furthermore, it was suggested that because of changing the solubility of the oligoradicals and hydrocarbon in the medium, the shape of the particles changed with changing the polarity of the medium. With decreasing the polarity of the medium, solubility of the oligoradicals in the medium increases and bigger polymer domains form on the surface of PS particles which can absorb higher amounts of decane. All of these can contribute to an increase in volume reduction after extraction of PEHMA/decane, resulting in various particle shapes. Further decreasing in polarity of the medium leads to an increase in the solubility of decane in the medium and decreasing the absorbed amount of decane by PS particles and PEHMA domains, resulting in lower volume reduction after evaporation of decane.

Light volatile liquid and gas shale reservoir potential of the Cretaceous Shaftesbury Formation in northeastern British Columbia, Canada

The geologic controls on reservoir properties and potential hydrocarbon (volatile, low-molecular-weight liquid and gas) resources of the Cretaceous Shaftesbury Formation in northeastern British Columbia have been investigated. Maturity varies from the oil to dry gas window (Tmax = 429–486C), with increasing maturity and depth of burial toward the south. The Tmax, in degrees Celsius, is the oven temperature at the peak generation of S2 during pyrolysis. Total organic carbon (TOC) content ranges between 0.64 and 8.0 wt. %, with an average of 2.2 wt. %. The TOC content distribution mirrors the trends in maturity, with lower TOC content in areas of high maturity. Kerogen is characterized as either type II-III or type III. The quartz content ranges between 33 and 66%, with higher quartz content in areas with lower TOC content and greater maturities. Porosity ranges between 4.5 and 14.6%, with higher porosities observed within shallower wells, low quartz content, or maturities, or a combination of all three. The porosity is reduced in high-maturity samples by mechanical compaction and silica cementation. Total gas capacities range between 4.5 and 24.8 cm3/g, and gas-in-place (GIP) estimates are between 0.98 and 3.39 bcf/(section meter). The calculated hydrocarbon generation is less than 3.6 bcf/(section meter), with light liquid generation between 3.7 and 516.2 MMBO. Present-day depths and organic maturity have strong influences on the hydrocarbon capacity more so than TOC content. Deeper, higher maturity samples in the south have the largest total gas capacity and GIP estimates (0.98–3.39 bcf/[section meter]). Maturity is within the dry gas window in the southern one-third of the study area. Highest volumes of light liquid hydrocarbons are found within the less mature northern part of the study area.

Unconventional Resources: Cracking the Hydrocarbon Molecules In Situ

R&D Grand Challenges - This is the sixth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee.The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT). Discoveries of accumulations of light crude oil are dwindling, and known resources are increasingly concentrated in areas that are predominantly accessible by state-owned or state-affiliated energy companies. As a result, the quality of (conventional) crude oil—particularly oil sourced from non-OPEC reservoirs—has been declining. The trend is bound to accelerate as unconventional hydrocarbons such as bitumen are brought into production to satisfy the world’s energy demand, which is expected to increase by slightly less than 50% in the next 20 years. Because the recovery and surface processing of these heavier molecules is more difficult, it is appropriate to ask whether a portion of the surface processing can be performed downhole (in situ). In fact, in the case of deeper-lying oil shale, it is the only realistic recovery option. There are three approaches by which in-situ manipulation of molecules can be accomplished: biological, chemical, and thermal. Although this article focuses on the thermal route, it should be noted that hybrid recovery methods may be more effective in satisfying the requirement to maximize economic value while minimizing water consumption, emissions, and land usage. The oil sands of Alberta, Canada, and the oil shale deposits in Colorado contain volumes of hydrocarbons that are at least comparable to the conventional oil resources in the Middle East (Fig. 1). Extraction by open pit mining is the dominant recovery method for commercial exploitation of the oil sands and is the only commercially practiced recovery method for oil shale. However, 70% to 80% of the oil sands in Alberta are deposited at intervals that are too deep (deeper than 60 m) to mine economically, and the same holds true for the richest and thickest sections of oil shale (deeper than 1,000 ft). Ever-increasing concerns about the environmental impact of mining (soil removal, tailings ponds, etc.) provide additional incentives toward the use of in-situ recovery methods.

Field appraisal and accurate resource estimation from 3D quantitative interpretation of seismic and CSEM data

The key questions in field appraisal are: What is the hydrocarbon volume, and how are the hydrocarbons distributed in the field? The ability to answer these questions accurately is critical for deciding whether to produce a field and for developing a production plan. Wells drilled during the appraisal phase provide well and flow-test data, which are combined with structural knowledge from seismic surveys to map the extent of the field and generate a reservoir model. The cost for appraising an offshore field can exceed US $100 million, and it is desirable to obtain the information required with fewer wells if possible. Quantitative interpretation of surface geophysical data provides reservoir properties between well locations and can, therefore, significantly reduce appraisal costs. A quantitative analysis of seismic data using well-log information will typically determine reservoir rock porosity. Other important parameters are hydrocarbon saturation, permeability, and net-to-gross ratio. Quantitative interpretation of several reservoir properties using only the seismic data is associated with significant ambiguity. To determine several of these parameters accurately, complementary geophysical data sets with different sensitivity characteristics are needed. Controlled-source electromagnetic (CSEM) data are sensitive to the fluid type and can provide additional information to determine the hydrocarbon saturation more accurately. We have developed a new quantitative interpretation workflow integrating seismic and marine 3D CSEM data for estimating the hydrocarbon volume and obtaining 3D distributions of the hydrocarbon pore volume. A performance test of the workflow has been carried out on the Troll West Oil Province (TWOP) in the Norwegian North Sea (Figures 1 and 2). This article describes our methodology and presents encouraging results.

Hierarchical Bayesian lithology/fluid prediction: A North Sea case study

Seismic 3D amplitude variation with offset (AVO) data from the Alvheim field in the North Sea are inverted into lithology/fluid classes, elastic properties, and porosity. Lithology/fluid maps over hydrocarbon prospects provide more reliable estimates of gas/oil volumes and improve the decision concerning further reservoir assessments. The Alvheim field is of turbidite origin with complex sand-lobe geometry and appears without clear fluid contacts across the field. The inversion is phrased in a Bayesian setting. The likelihood model contains a convolutional, linearized seismic model and a rock-physics model that capture vertical trends due to increased sand compaction and possible cementation. The likelihood model contains several global model parameters that are considered to be stochastic to adapt the model to the field under study and to include model uncertainty in the uncertainty assessments. The prior model on the lithology/fluid classes is a Markov random field that captures local vertical/horizontal continuity and vertical sorting of fluids. The predictions based on the posterior model are validated by observations in five wells used as blind tests. Hydrocarbon volumes with reliable gas/oil distributions are predicted. The spatial coupling provided by the prior model is crucial for reliable predictions; without the coupling, hydrocarbon volumes are severely underestimated. Depth trends in the rock-physics likelihood model improve the gas versus oil predictions. The porosity predictions reproduce contrasts observed in the wells, and mean square error is reduced by one-third compared to Gauss-linear predictions.

The effects of pyrobitumen on oil cracking in confined pyrolysis experiments

Three sets of pyrolysis experiments were performed for oil alone, pyrobitumen alone and oil plus pyrobitumen at two heating rates of 2°C/h and 20°C/h in confined systems (gold capsules). The results of these experiments demonstrated that pyrobitumen significantly promoted the generation of methane while not only inhibiting the generation, but also accelerating the cracking of wet gases during oil cracking experiments in confined systems. Furthermore, the cracking rate of wet gases increases with pyrobitumen/oil ratios. As a result, C1/ΣC1–5 ratio is significantly higher in the experiment of oil plus pyrobitumen than oil alone at the same temperature conditions. Although the amount of methane increased, the weight of the total gaseous hydrocarbons decreased and the volume of the total gaseous hydrocarbons remained unchanged with the addition of pyrobitumen. This result can be ascribed to some oil and wet gas components being combined with the pyrobitumen phase and released later mainly as methane at higher temperatures and maturities. The activation energies for the generation and cracking of wet gases decrease with the carbon number and are relatively lower in the experiments of oil plus pyrobitumen than oil alone. The distribution ranges of the activation energies for the generation of wet gases also decrease with the carbon number.

Analysis to Effective Elastic Modulus and Porosity for Artificial Bone Scaffold with Hydroxyapatite Microspheres

The effective elastic modulus of hydroxyaptite (HA) microspheres composite scaffold is determined by the HA microspheres’ elastic modulus, accumulation topology model and the porosity. Experiments showed that different accumulation pattern and porosity has different modulus for bone scaffold. Furthermore, porosity and accumulation pattern are affected directly by the adhesive thickness. Here, we elucidate the effect of the scaffold parameters on bone sitffness and porostiy by means of a mathmatically based approach. Based on ANSYS simulation platform, the effective elastic modulus of HA microspheres scaffold was demonstrated. And the effective elastic modulus of artificial bone scaffold with different adhesive thickness was calculated by using APDL. Use the void fraction to illustrate the porosity of HA microspheres scaffold, which is an important consideration when attempting to evaluate the potential volume of water and hydrocarbons it may contain. By analysis of the optimization results, the effective elastic modulus reaches the maximum when the adhesive layer thickness is 0.05 mm, while the corresponding porosity is 0.5231

Succession of Genetic Diversity of Botryococcus braunii (Trebouxiophyceae) in Two Japanese Reservoirs

Abstract Botryococcus braunii is a green colonial alga that produces large volumes of liquid hydrocarbon. Therefore, B. braunii is expected to be useful as an alternative fuel resource. Natural blooms of B. braunii have been recorded in several lakes and reservoirs. Elucidation of natural B. braunii blooming would provide important information for the development of an open-pond cultivation system. In this study, we periodically assessed the genetic diversity and colony density of B. braunii populations, along with several environmental parameters, in two Japanese reservoirs (provisionally called “N” and “S”) from December 2008 to December 2009. Reservoir N had low numbers of B. braunii colonies whereas Reservoir S was characterized by periodic density increases that occurred in December 2008, and in March, September, and December 2009. Population genetics analysis using specific environmental sequences (PGA-SES method) was conducted for B. braunii populations for the first time. Among the B. braunii -dominated samples of Reservoir S, high levels of genetic diversity were observed in December 2008 and March 2009, whereas the diversity levels in September and December 2009 were low. The results suggest that B. braunii periodicity can be categorized into a high genetic diversity type and a low genetic diversity type. The high genetic diversity type may be caused by simultaneous growth of many genotypes, whereas the low genetic diversity type seems to be explained by increases in the cell density of only a few adapted genotypes.

The influence of radiofrequency electromagnetic fields on the adsorption processes in porous media

The experimental results of the polar hydrocarbon adsorption in saturated porous media after radio-frequency (RF) electromagnetic (EM) influence and the thermal heating for comparison are presented. Temperature dependences of the extracted volume of hydrocarbons from models are shown. Comparing the obtained data an additional influence of RF EM field on the desorption of asphaltenes from the porous media surface has been found, that leads to an increase of the extraction of hydrocarbons from the models. The thermodynamic substantiation and mathematical modeling of heat and mass transfer in a saturated porous media under RF EM influence are used as the basis of theoretical study. The equation of sorption kinetics based on the Henry’s Law includes a summand that represents the contribution of thermal and EM fields is to be considered. Researches have discovered that the adsorption process slows down under RF EM field influence, which has a positive effect on the filtration ability of the saturated rock. Investigation of the field influence on the asphaltene adsorption process using atomic force microscopy (AFM) was conducted to identify the mechanism of adsorption and desorption of polar components on the surface of the porous medium under the RF EM field influence.

Structures and petroleum prospects of the Saramaguacán basin, Cuba, from 3D inversion of gravimetric data

Se presentan nuevas particularidades estructurales de la cuenca Saramaguacán, Cuba, a partir de la inversión 3D de datos gravimétricos, constreñidos por información de pozos y geología de superficie. Esas particularidades muestran una tectónica compleja de procesos de cabalgamiento, revelando el esquema estructural más probable dentro de la cuenca, el cual indica estructuras en formas de rampa y plataforma, así como la ubicación y geometría de la cuenca y varias sub-cuencas. También se conocen las ubicaciones y comportamiento en profundidad de las principales fallas, y se sugieren posibles nuevas fallas. A las diferentes formaciones rocosas se le determinaron las variaciones de su geometría, profundidad y espesor. Esta determinación posee particular importancia para las rocas sedimentarias (rocas colectoras) y las rocas del paleomargen (rocas madres) porque constituye la base para futuras investigaciones orientadas a seleccionar los mejores sitios para ubicar las perforaciones petroleras y calcular el volumen de hidrocarburo que pueden almacenar las rocas colectoras. Ambos grupos de rocas son potenciales para la prospección petrolera. A 4 km de profundidad se localizaron las rocas madres del sistema petrolero cubano, asociadas a las rocas carbonatadas del paleomargen. Las rocas colectoras alcanzan 10 km de profundidad. El modelo 3D obtenido apoya la hipótesis de un emplazamiento tectónico de sur a norte de las ofiolitas y las rocas volcánicas cretácicas, sobre las secuencias terrigenous-carbonatadas del paleomargen de Bahamas. Las particularidades estructurales mostrada por el modelo constituyen indicadores de la tectónica compresiva que originó la cuenca Saramaguacán en el Mesozoico-Terciario. También indican que la cuenca Saramaguacán posee condiciones favorables para la preservación de petróleo.