Thin Reservoir Research Articles

Enhanced thermal conductivity and reduced viscosity of aegirine-based VR/VGO nanofluids for enhanced thermal oil recovery application

The depleting of the available conventional energy supplies together with an industrial shift towards unconventional resources like heavy oil/bitumen has become more pronounced. The steam-based heating methods are primarily used by the oil industry for the heavy oil/bitumen recovery. However, the thermal recovery methods are energy-intensive and have limited applications, especially for both thin and deep reservoirs. Therefore, there is a high priority need to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection. Hence, the continual improvement of this technique is of utmost importance. This study aims to propose a new injecting nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading and recovery. Here we report a new type of copper-based nanofluid using a blend of vacuum gas oil (VGO) and vacuum residue (VR) as the mother solvent. The nanoparticles were prepared by low-temperature hydrothermal synthesis route. Their detailed surface, morphology and size characterizations were achieved by X-ray diffraction, dynamic light scattering and scanning electron microscopy. The stable nanofluids were prepared by dispersing copper-based nanoparticles in a mixture of VGO and VR, at different ratios and temperatures. A set of measurements to determine the thermal conductivity and viscosity of the nanofluid with different loading of nanoparticle were performed. The thermal conductivity values of nanofluid systems are substantially higher than that of the base fluids. The nanofluid for 2 wt% of copper-doped aegirine nanoparticles dispersed in VGO and VGO/VR mixture exhibits a maximum thermal conductivity of 20% and 24%, respectively. It was found that the thermal conductivity of nanofluids increases with decreasing the hydrodynamic particle size. Moreover, the presence of chemo-physical interactions between nanoparticles and base fluid further enhances the thermal conductivity. Also, the temperature augmentation in a range from 80 to 110 °C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. This particular nanofluid may find potential applications in enhancing heavy oil upgrading and recovery.

Development of East Baghdad Oil Field By Clusters of Horizontal Wells

There are varieties of reasons lead for drilling horizontal wells rather than verticals. Increasing the recovery of oil, especially from thin or tight reservoir permeability is the most important parameter.
 East Baghdad oil field considered as a giant field with approximately more than 1billion barrel of a proved reserves accompanying recently to low production rate problems in many of the existing wells.
 It is important to say that presence of of horizontal wells in East Baghdad field especially by converting some of already drilled wells by re-entry drilling horizontal sections may provide one of best solutions for the primary development stage in East Baghdad field which may be followed by drilling new horizontal wells or using multilateral wells.
 Advance software (Well Test/FAST) has been used to convert the production data for the already drilled vertical wells to horizontals to simulate the productivity. It can be concluded that no measurements available for the ratio of anisotropy (Kv/Kh); in East Baghdad Oil Field therefore, the wells productivity has been estimated using wide range of anisotropy ratios that will help the field operator to determine exactly wells productivity. Moreover, it helps to recommend the effectiveness of applying hydraulic fracturing in improving horizontal well productivity.
 The results show that it could be used well EB-32 as a re-entry horizontal well with an optimum section length of 1500-2000ft wich give the best production rate. The same result could be stated for EB-10 with somewhat higher productivity than EB-32.

Low-Temperature Bitumen Recovery from Oil-Sand Reservoirs Using Ionic Liquids

Summary Steam injection is widely used for bitumen recovery. However, steam is not efficient for shallow or thin reservoirs because of heat loss in the wellbore or to surrounding formations. Numerous alternatives have been proposed, including the addition of solvents and replacement of steam with volatile solvents. Here, we describe a new technology that combines nonvolatile ionic liquids (ILs) and waterflooding for bitumen recovery that can deliver high recovery at ambient temperature. Different ILs were designed for complete dispersal/dissolution of bitumen at ambient temperature. The designed ILs were tested in coreflood experiments with high–grade oil–sand ore from Alberta. Two different scenarios were tested: continuous injection of ILs at different injection rates and injection of a slug of ILs followed by water injection. Different slug volumes were tested at a constant injection rate. After ILs injection, the oil sand was removed from the column, and the remaining bitumen was quantified using a modified Dean–Stark method. Viscosity and solid–content measurements of the recovered samples at breakthrough were conducted. Bitumen recovery by the designed ILs can be thought of as a solution mining process. Tuning the physical and chemical properties of the ILs is the most important aspect of achieving the desired interaction with the oil–sand system. Properties of the designed IL depend on the selected cation and anion, and the strength of their intermolecular interaction. Primary amines mixed with the oleic acid chosen for IL1 form a viscous IL that can recover bitumen, leaving a slight amount of bitumen behind, but a large pressure gradient. Changing the cation to tertiary amines produces significantly less–viscous ILs, which completely recover the bitumen in the oil–sand column. Moreover, the cation can be tailored to significantly minimize the fines (clay) migration and viscosity of the recovered bitumen and to provide compatibility with an aqueous phase. In all cases, these recoveries are significant, compared with the currently used technologies. This work proves that bitumen recovery from oil sand is possible at low temperatures by means of a process analogous to solution mining with the design of the proper ILs, in contrast to viscosity–reduction processes achieved by thermal methods. The properties of these ILs can be tuned for different recovery mechanisms. Thus, this work establishes the basis for developing a new class of in–situ recovery processes with high recovery efficiencies and low environmental impact.

Middle Ordovician multi-stage penecontemporaneous karstification in North China: Implications for reservoir genesis and sea level fluctuations

Palaeokarsts contain important information about subaerial exposures due to sea-level regression, which has been considered as a dominant genesis of reservoirs. Herein we describe a typical sedimentary core section of the Middle Ordovician Majiagou Formation that records multi-stage penecontemporaneous karstification in North China. Petrographic observations and stable isotopic data reveal high-frequency penecontemporaneous subaerial exposure and resulting karstification. Evidence for this includes erosional surfaces, gypsum breccias, facies-controlled dissolution vugs and vadose infillings, fabric-selective dissolution, and negative carbon and oxygen isotopic excursions. Karstification generally occurred in the middle and upper parts of an upward-shallowing sequence within a single depositional cycle, leading to meteoric water dissolution of shoals and mounds. This significantly enlarged the primary pores and generated new reservoir space. As such, high-quality hydrocarbon reservoirs became well developed, which are regularly and cyclically stacked at locations a few meters below the multiple exposure surfaces. Reservoir porosity also varies systematically with the high-frequency sedimentary cycles, and is generally at a maximum in the middle and upper parts of a cycle. The multi-stage penecontemporaneous subaerial exposure and resulting karstification reflect high-frequency changes in relative sea level in North China at this time, thereby providing a framework for identifying thin carbonate reservoirs in and around the Ordos Basin.

Sparse spectral attributes to detect hydrocarbons: A case study from deep dolomite reservoirs

Hydrocarbon detection is always one of the most critical sections in geophysical exploration, which plays an important role in subsequent hydrocarbon production. However, due to the low signal-to-noise ratio and weak reflection amplitude of deep seismic data, some conventional methods do not always provide favorable hydrocarbon prediction results. The interesting dolomite reservoirs in Central Sichuan are buried over an average depth of 4500 m, and the dolomite rocks have a low porosity below approximately 4%, which is measured by well-logging data. Furthermore, the dominant system of pores and fractures as well as strong heterogeneity along the lateral and vertical directions lead to some difficulties in describing the reservoir distribution. Spectral decomposition (SD) has become successful in illuminating subsurface features and can also be used to identify potential hydrocarbon reservoirs by detecting low-frequency shadows. However, the current applications for hydrocarbon detection always suffer from low resolution for thin reservoirs, probably due to the influence of the window function and without a prior constraint. To address this issue, we developed sparse inverse SD (SISD) based on the wavelet transform, which involves a sparse constraint of time-frequency spectra. We focus on investigating the applications of sparse spectral attributes derived from SISD to deep marine dolomite hydrocarbon detection from a 3D real seismic data set with an area of approximately [Formula: see text]. We predict and evaluate gas-bearing zones in two target reservoir segments by analyzing and comparing the spectral amplitude responses of relatively high- and low-frequency components. The predicted results indicate that most favorable gas-bearing areas are located near the northeast fault zone in the upper reservoir segment and at the relatively high structural positions in the lower reservoir segment, which are in good agreement with the gas-testing results of three wells in the study area.

A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery

A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.

A deterministic geomodeling case study for a thin clastic reservoir: The Second Wall Creek Sand, Teapot Dome field, Wyoming, USA

In this case study, we geomodeled the Upper Cretaceous Second Wall Creek Sand (SWCS) of the southern Teapot Dome field, Wyoming, USA, using public domain seismic and well-log data. The SWCS is an at-or-below seismic-resolution (about 20 m), fluvial-deltaic reservoir and has been the most productive in the field. The goemodeling procedure consisted of structural modeling of the depth 3-D grid (30 m × 30 m × 1 m cells) and petrophysical modeling for porosity and net-to-gross (N/G). The seismic data were enhanced by spectral balancing to resolve the SWCS. Facies modeling was not necessary because a facies analysis of gamma-ray logs and lithofacies and stratigraphic-discontinuity seismic attributes suggests a uniform facies. The porosity and N/G were modeled by neural network multi-attribute transform (NN-MAT). NN training included the absolute and relative impedances and three representative isofrequencies in addition to the conventional amplitude- and frequency-based attributes. The modeled porosity varies from less than 8% to over 18% with an average of 16.7% which agrees with the reported averages. The modeled N/G values range from about 0.2 to over 0.8 with an average of 0.7 which is greater than the reported average (0.5). The porosity and N/G models may not be optimal because only a few wells and a small number of the time samples for the thin reservoir interval were used in NN training. The geomodeling workflow presented in this study is optimized for thin reservoirs and can be used when facies modeling is difficult because NN-MAT computes petrophysical properties without being guided by facies models.

Study On Thin Differential Interpretation Method Of 0.2 m High Resolution Logging Series in Sabei Development Zone

Sabei development zone has entered a stage of development for determining remaining oil distribution of plane scattered, longitudinal mainly concentrated on the thin layer and thick thin poor parts of the reservoir, the existing in DLS logging series layered rate will not form a complete set, and the problem of insufficient depth lead to form a complete set of logging interpretation of water-out reservoirs technology, on the untabulated reservoir and thin poor reservoirs under 0.4 meters can’t realize the quantitative explanation, become the bottleneck of poor thin reservoir interpretation in the future. The development of the new series of 0.2m can effectively solve the problem of thin differential zone interpretation by improving the vertical resolution and horizontal detection depth, and establishing the logging interpretation technology matching this technology, so as to meet the need of fine tapping remaining oil in the development stage of extra-high water-cut development in sabei development zone and better guide the dynamic development and adjustment of oilfield.

Technologies for the benefit development of low-permeability tight sandstone gas reservoirs in the Yan'an Gas Field, Ordos Basin

The Yan'an Gas Field is located in the southeastern part of the Ordos Basin, and its low-permeability tight sandstone gas reservoirs are characterized by thin reservoirs, poor physical properties and complex overlapping relationships. In addition, its surface is loess tableland, which makes it difficult to predict reservoirs by using seismic data. As a result, existing engineering technologies for gas field development cannot support the efficient development of this field. In order to optimize the development methods and technologies of the Yan'an Gas Field, the Yanchang Petroleum (Group) Co. Ltd. has developed to a set of key technologies suitable for the benefit development of this field concerning reservoir prediction, well pattern optimization, drilling and completion, reservoir protection, fracturing stimulation and ground gathering and transportation after nearly ten years of theoretical and technical researches. First, an effective reservoir prediction technology based on dynamic knowledge base was developed. It improves the drilling ratio of effective sandbody dramatically and achieves the accurate tracking of stable single sandbody in the range of 3–5 m. Second, a three-dimensional exploitation mode of hybrid well pattern based on the irregular diamond-shaped well pattern was established. It includes the multi-layer commingled production of cluster well and the single-layer production of horizontal well. Compared with regular well patterns, the well number is reduced by 6.9% and well pattern control is increased by 8%. Third, high-efficiency drilling technology for vulnerable reservoirs with collapse and leakage in the same well was developed. It improves wellbore wall stability, shortens drilling cycle and protects reservoir. Fourth, the multi-layer long-span fracturing of vertical/directional wells in one operation and the CO2 and hydraulic fracturing treatment of horizontal wells were realized to improve single well production significantly. Fifth, the medium-pressure gathering and transportation system in loess tableland with downhole throttling, branch-on-branch inter-well tandem and centralized alcohol injection as the core technologies was established. It reduces workload, shortens construction cycle and improves economic benefit. In conclusion, these development technologies play a crucial role in the development, appraisal and productivity construction of the Yan'an Gas Field. Through the application of these key technologies, the benefit development of this field is realized with an annual natural gas production capacity of 50 × 108 m3. Furthermore, they are conducive to the enrichment and development of the theories and technologies for developing tight sandstone gas reservoirs in China, and they can be used as a reference for the development of similar gas fields.

Seismic sedimentologic study of facies and reservoir in middle Triassic Karamay Formation of the Mahu Sag, Junggar Basin, China

Abstract The top sandstone (S1) of the middle Triassic Karamay Formation (T2k) is one of the major pay zones in the Mahu field, Junggar Basin, northwestern China. Both spatial distribution and internal architecture of the reservoirs are important for resource evaluation and petroleum production in the field. Seismic sedimentology, an integrated study of seismic geomorphology and seismic lithology, was applied to well and three-dimensional (3-D) seismic data to analyze distribution of sedimentary facies and reservoirs. Lithologies in the study area consist of conglomerate, sandstone, and mudstone. Acoustic impedance (AI) of mudstone (6–9 × 106 kg/[s*m2]) is lower than the other two lithologies, which have similar AI values (9–14 × 106 kg/[s*m2]). Therefore, seismic amplitude can distinguish mudstone from conglomerate and sandstone, but fails to differentiate conglomerate from sandstone. Seismic geomorphology was employed to qualitatively predict distribution of sandstone and conglomerate respectively using frequency decomposition, seismic-attribute extraction, and red-green-blue (RGB) color-blending techniques. In the seismic lithologic study, principal component analysis (PCA) was utilized to transfer multiple seismic attributes into principal components. Selected principal components were then fit with cumulative reservoir thickness interpreted from porosity-log data, resulting in quantitative estimation of interwell thin (10 m or thinner) reservoir distribution. Meandering fluvial facies were recognized for the first time in the previously interpreted fan-delta facies zone. Meandering channels formed when the lake level rose in relatively humid climate during a time with few tectonic activities. The previously formed fan-delta was substituted by a later formed meandering channel, which flowed into the southwestern lake from the north. Sediment distribution was controlled by accumulation space or paleogeomorphology restored by cast method; sediment is thick in paleolow terrains and thin in paleohigh areas. Locality of reservoir rock is basically coincident with sandstone distribution. Thick reservoir rocks with high porosity (greater than 10%) are located mainly in areas with moderately thick sandstones formed in point-bar subfacies of fluvial systems and in lower-fan subfacies of the fan-delta system. Higher petroleum production in individual wells drilled in the fluvial system indicates superior physical properties there. As a result, locating point-bar subfacies is key to improving hydrocarbon exploration and development.

Technology Focus: Multilateral and Complex-Trajectory Wells (May 2019)

Technology Focus When students ask me about the most important way to maximize recovery, my answer is long directional wells. These wells have revolutionized the oil industry and are drilled under conditions never imaginable years ago. One outstanding example is the Troll field in Norway. The field consists of large, very thin reservoirs, down to 30 ft thick, which are drained by multibranch horizontal wells with horizontal departures approaching 18,000 ft. Not only have many drilling challenges been overcome, but also, from a production perspective, the wells are equipped with intelligent technology such as autonomous gas stop to maintain the pressure drive for the oil. Initially of no commercial interest because of a lack of technology, this field has been a very important driver for the current state of the art for long horizontal wells. Troll has been Norway’s largest oil producer in recent years. This has been made possible by the development of long-horizontal-well technology. The oil industry is currently undergoing a technological transformation that will add value, improve processes, and reduce cost. Future drilling engineers will have knowledge of robotics, automation, and organizational efficiency, which is highly appealing for recruitment. A prerequisite for this step change is the industry’s high level of technology. The selected papers address various aspects of horizontal wells. A field case of how to plan and drill through highly depleted reservoirs is given in paper OTC 28517. Three depleted zones must be penetrated before drilling into the untapped reservoir with a low drilling margin. This is a good example of drilling an extended-reach well using an integrated approach between various disciplines. Another example is given in paper SPE 191436, which shows how a complex U-shaped well path from old wells can be used to obtain good reservoir exposure to drain depleted wells further. Equipment is continuously improved, and paper SPE 189947 presents new ultrasonic technology to evaluate the state of multilateral junctions. SPE 191271 Extended-Reach Wells in Unconsolidated Sands in Bolivia by Gabriel Dordoni, Pluspetrol Bolivia OTC 28971 Correlation of Numerical Simulation and Digital-Image-Correlation Strain Measurements for a Multilateral Junction While Subjected to High Internal Pressure by Aihua Liang, Halliburton, et al. SPE 192672 Wireline Tractor Conveyance—A Technology Game Changer for the Gulf of Thailand by Sarunya Jongnarungsin, Mubadala Petroleum, et al.

Designing a pragmatic solution for complex numerical modeling problem in thinly laminated reservoirs

Unquestionably, water breakthrough into the producing wells is one of the biggest threats to the development and production of oil and gas reservoirs around the world. The predicted water production profile from a numerical simulation model directly affects the estimated recoverable volumes and hence the decision making process for the field development and the facility design to handle the produced water. The problem of reliably predicting the water production profile exacerbates when dealing with thinly laminated sand reservoirs. Calculating the total water saturation (SWT) using well log data in the hydrocarbon zone in this type of reservoirs is adversely affected by the convoluted readings of the conventional logging instruments whenever the resolution of the laminations goes beyond the tool resolution (i.e. 0.5 feet). This in turn leads to unrealistic movement of water in the model, pre-mature water breakthrough, pessimistic forecast of oil and gas and over-estimation of required water treatment system capacity. Although some advancement has been made in the identification of these types of reservoirs, their reservoir modeling still remains a challenge for petroleum industry due to limitations in developing proper methods to estimate petrophysical properties using conventional logs and also the computational cost of running extremely fine numerical models. In this study various issues and challenges of modeling these types of reservoirs are addressed. A workflow for numerical modeling of thinly laminated sands at affordable vertical grid resolutions has been proposed that properly uses the available geological, petrophysical and engineering data in an effective (vs. total porosity) system. The methodology of reproducing the volumetrics and capturing heterogeneity at various scales, through proper rock-typing and use of net to gross ratios are discussed in detail. The data requirement for modeling, reservoir management and performance monitoring of thin beds is also elucidated. The presented workflow provides a simple yet pragmatic tool that can help best represent the thinly laminated sands at affordable measurement and computation costs, mitigate the risks associated with thin bed reservoir development and increase the value of field development planning.

A union of spectrum and cepstrum: Recipe for thin-bed delineation

The resolution limit of seismic data is an intricate issue that depends not only on frequency and data quality (signal-to-noise ratio) but also on the tools and technology used to analyze seismic response. In this context, the subject of thin-bed delineation is extremely significant for coal-laminated (causing large acoustic impedance contrasts) clastic sequences of the Western Onshore Basin, India. Most of the clastic reservoirs in the area are of subseismic resolution (below 10 m in thickness) due to the low dominant frequency available in seismic data (19–35 Hz). This is where improving seismic resolution is essential for a detailed structural and stratigraphic interpretation. We have implemented a modified workflow with which, by using state-of-the-art techniques of time-frequency decomposition and cepstral analysis, significant seismic bandwidth extension has been achieved. This in turn yields improved vertical resolution of the seismic data with better geologic interpretability. Our approach is named the “syn-cepstral method” after its two integral constituents — synchrosqueezing transform and cepstral analysis. Applying the syn-cepstral method produces better well-to-seismic ties and resolves additional events in comparison to the original seismic data. The validity of syn-cepstral methodology has been demonstrated by 1D and 2D modeling studies followed by application to a 3D seismic data set from the Western Onshore Basin of India. The improvement in thin-bed delineation arising from the increased bandwidth of the resultant data has been validated by well-to-seismic ties and amplitude map interpretation. Thus, while thin clastic reservoir beds in the logs show no discernible presence in the original seismic data, upon application of the syn-cepstral method, the resultant seismic data show improved interpretability of these units.

Successful infill drilling campaign using fit-for-purpose seismic technologies doubles oil production and extends field life at Lakshmi Field, Gulf of Cambay, western India

The offshore Lakshmi Field, located in the southern part of Cambay Basin in the CB/OS-2 block in western India, is a success story of transitioning from a plateauing gas field to an oil-producing asset. Hydrocarbons sourced from Hazira Shale at Lakshmi Field are trapped in inversion-related four-way dip closures. The reservoirs are within the Miocene-age Tarkeshwar and overlying Babaguru formations; both have excellent reservoir quality with porosity ranging from 25% to 30% and Darcy-scale permeability. During the initial exploration stage, presence of oil was established in the deeper lower Tarkeshwar sands. However, the full oil potential of the field was not realized in the early stage of development due to difficulty in characterizing laterally and vertically discontinuous thin sands. These sands are often not detected in conventional 3D seismic data due to severe attenuation-related masking by overlying thick gas sands. Given the uncertainty of the oil potential of the field, a revised look using advanced seismic technologies was undertaken to drive a new infill drilling campaign. Seismic reprocessing using Q-tomographic inversion was performed to address the gas-attenuation problem, resulting in an improved seismic image. The new seismic data enabled characterization of thin reservoir sands using analytical techniques such as spectral decomposition and amplitude-variation-with-offset (AVO) attribute analysis. An integrated reservoir-characterization approach using field analogs, interpretation within a sequence stratigraphic framework, concepts of seismic geomorphology, and quantitative seismic analysis helped identify optimal areas of the sand fairway for infill well placement. Several infill wells have since been drilled that encountered good pay zones, validating the integrated approach. This successful campaign doubled oil production at Lakshmi and extended the field life by increasing reserves.

Geology-engineering integration for low-permeability and thin marginal reservoirs: a case study on Zanazour oilfield, Pre-Caspian Basin

Geology-engineering integration for low-permeability and thin marginal reservoirs: a case study on Zanazour oilfield, Pre-Caspian Basin

Ten Technologies From the 1980s and 1990s That Made Today’s Oil and Gas Industry

Special Section: The Value and Future of Petroleum Engineering Contrary to popular imagination, which favors John Wayne stereotypes heroically rescuing the oil industry with wrench and hammer, the oilfield is a place of exquisite engineering, the match of anything on Earth, a marvel of innovation at the biggest and smallest scales. The office-block sized blowout preventers on the ocean floor or the minute geopositioning electronics inside a logging while drilling (LWD) tool both are designed to operate perfectly within exacting environmental specifications. Almost every aspect of upstream exploitation is the result of exhaustively leveraging the glorious value chain of math, science, and engineering. Along this trajectory, failure is met more often than success, as ideas and developments are tried out and eventually fine-tuned until something begins to work reliably. The journey is not for the faint-hearted. Whether it be one obsessive individual or a team with an equal desire to win, both energy and imagination must be sustained at every hurdle, to force progress and eventual success. This is as valid for the glamorous game-changing innovation as it is for a leap-of-faith improvement to existing technological practice. Since the 1980s, our industry has experienced a technology renaissance all along this innovation spectrum—the oil price volatility in this modern era of our industry certainly focused minds on doing things more efficiently at less cost. As a celebration of these years of technical innovation, we now make so bold as to list perhaps 10 of the most significant contributions. No doubt it is foolhardy to propose such a list because we all have an opinion on what should be on it. Nevertheless, there is surely enough common ground to guarantee some degree of objectivity. What may be objectionable is limiting the number to 10. Within that constraint, however, just the intellectual and practical bravado displayed surely merits all 10 to be included. 1981: Horizontal Wells Increase Production The Soviet Union pioneered horizontal wells in the late 1960s only to turn its back on furthering the development of the practice in favor of vertical wells that were easier and faster to drill. But the mantle was picked up by Jacques Bosio, a drilling engineer with French oil company Elf Aquitaine, which needed horizontal drilling to intersect fractures and increase production from a karst reservoir found off the Italian coast, the Rospo Mare field. In 1981, for twice the cost of a vertical well, horizontal drilling was sanctioned. The first well would bring in 3,000 B/D—more than 20 times its off-set vertical well. By the mid-1980s, horizontal drilling was seeing wider adoption as a way to target thin oil and gas reservoirs in Texas, the Middle East, and the North Sea. Operators had known about these skinny hydrocarbon- bearing layers for years—now they had a way to contact them with enough surface area to make money. Bosio would go on to become the first SPE President from outside the US, in 1993.

Porosity and carbon dioxide storage capacity of the Maryville–Basal sands section (middle Cambrian), Southern Appalachian Basin, Kentucky

The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (φe), clay volume (Vc), and supercritical CO2 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The φe and Vc were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average φe and Vc calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated φe exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO2 storage volume supercritical CO2 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO2 storage reservoirs in this area.

Application of Seismic Motion Inversion in the Third Member of the Shahejie Formation in the Northeastern Kenli

The reservoirs in the third member of the Shahejie Formation in the northeastern Kenli are thin and laterally changing, so the traditional seismic attributes and inversion techniques have no ideal prediction effects for them, which fails to meet the needs of exploration evaluation. With the first application of the Seismic Motion Inversion technique in the work area, based on the seismic data, and guided by sedimentary laws and seismic geological features, this study carried out the HF inversion by making full use of the constrained seismic logging parameters, through the process that the waveform similarity and spatial distance constrained the preferable seismic trace to participate in the inversion operation. The inversion results show that the sandstone body structure and distribution pattern in the study area are clear. This improves the prediction ability of interwell thin reservoirs, and well describes the overlap boundary of thin-layer sandstone, having guiding significance for the next exploration and deployment work in this area.

Multizone Casedhole Frac Packs and Intelligent-Well Systems Improve Recovery in Subsea Gas Fields

Summary A nine–well subsea development project has been completed using casedhole frac packs (CHFPs) for sand control and multizone intelligent–well systems (IWSs) to improve recovery from a series of shallow, low–pressure gas reservoirs. In these wells, CHFPs have been installed to provide reliable sand control over the long, low–net–to–gross–ratio sand/shale target sequence: typically, three to six frac packs per well. This outer CHFP completion is then augmented with a multizone IWS, consisting of isolation seals, surface–controlled zonal–isolation valves, and downhole–pressure/temperature (DHP/T) gauges. The IWS string is run as a separate inner string to provide flow–monitoring capability and allow shutoff of zones producing high water volumes. This critical water–shutoff capability eliminates the risk of one or more high–water–production zones loading up and killing adjacent low–pressure gas zones, with the associated loss of reserves. To date, a total of nine wells have been completed and are being produced from three subsea gas fields. To maximize recovery from the fields’ numerous but relatively thin gas reservoirs, production wells are completed over three to six separate intervals. These frac–packed intervals are then grouped to allow flow control and pressure/temperature monitoring to occur through up to six surface–operated interval control valves (ICVs) and associated downhole gauges. This combination of sand control and intelligent–well control has provided an ability to perform multirate tests (MRTs) and pressure–buildup (PBU) tests on each reservoir interval to detect the start of water production or identify other impending production issues. After approximately 6 years of production service to the October 2018 date of this paper, 16 of the 34 zones completed in the nine–well project have been shut in to eliminate high water production. These water–shutoff actions performed using the surface–controlled ICVs are estimated to have improved gas–recovery factors from 50 to 60% without requiring rig intervention. This paper describes the reservoir challenges addressed and the completion–design and –operating practices used in this successful program.

Revealing the Role of Gold in the Growth of Two-Dimensional Molybdenum Disulfide by Surface Alloy Formation.

The formation of Mo/Au surface alloy during Au-assisted chemical vapor deposition (CVD) of MoS2 is confirmed by a series of control experiments. A metal-organic chemical vapor deposition (MOCVD) system is adapted to conduct two-dimensional MoS2 growth in a controlled environment. Sequential injection of Mo and S precursors, which does not yield any MoS2 on SiO2 /Si, grows atomically thin MoS2 on Au, indicating the formation of an alloy phase. Transmission electron microscopy of a cross-section of the specimen confirms the confinement of the alloy phase near the surface only. These results show that the reaction intermediate is the surface alloy, and that the role of Au in the Au-assisted CVD is the formation of an atomically thin reservoir of Mo near the surface. This mechanism is clearly distinguished from that of MOCVD, which does not involve the formation of any alloy phases.