bluuebunny/crossref_metadata_2025 huggingface dataset:
A novel artificial intelligence automatic detection framework to increase reliability of PLT gas bubble sensing
Authors: Katterbauer Klemens , Marsala Alberto F. , Schoepf Virginie , Donzier Eric
Published: December 2021

Production logging tools (PLTs) and formation testing, even in logging while drilling (LWD) conditions during underbalanced drilling, are key technologies for assessing the productivity potential of a gas well and therefore to maximize recovery. Gas bubble detection sensors are key components in determining the fluid phases in the reservoir and accurately quantify recoverable reserves, optimize well placement, geosteering and to qualify the production ability of the well. We present here a new nonlinear autoregressive - breakdown artificial intelligence (AI) detection framework for PLT gas bubble detection sensors that categorize in real-time whether and which sensors become unreliable or have broken down during the logging measurements. AI tools allow the automatization of this method that is critical during data quality control of post-drilling PLT, but it is essential when the measurements are performed in LWD as data assessment and processing need to occur in real-time. This AI framework was validated on both a training and testing dataset, and exhibited strong classification performance. This method enables accurate real-time breakdown detection for gas bubble detection sensors.
A review on current trends and prospects in the pyrolysis of heavy oils
Authors: Ore Odunayo T. , Adebiyi Festus M.
Published: December 2021

Increasing global demand for energy is an aftermath of an upsurge in world population and industrialization. The exploration of heavy oils such as oil sands, tight oils, and heavy oils, is thus becoming a necessity in a bid to alleviating the energy crisis. The processing of fossil fuels using conventional methods is known to have devastating effects on global warming and ocean acidification. This has brought about innovation and development of environmental-friendly processing technologies. Of these processing technologies available to date, pyrolysis is the most widely employed due to low operating complexity and economic cost. As revealed by the reviewed studies, the distribution of products formed during pyrolytic processes is a function of residence time, heating rate, the temperature of reaction, and reactor design. The latter significantly influenced the qualitative and quantitative yield of products formed during pyrolysis. Operating conditions of temperature, pressure, and catalyst are also influential factors in determining the product yields. Most research efforts in the last 30 years have identified that optimum production of pyrolytic oils occurred between thermal cracking temperature of 350 °C and 500 °C. The plausible mechanisms of pyrolysis are the free radical chain mechanism involving the homolytic cleavage of the C–C bond, and the electron transfer mechanism. This review pointed out the current status of the adoption of pyrolysis by petroleum and petrochemical industries as a processing technology for low-value heavy oils into high-value light fractions. The findings of the studies reviewed can help for better understanding of the optimum pyrolysis conditions required for maximum production of oils and gases. It will also help in carefully choosing the most sustainable approach in a bid to averting economic and environmental risks.
Enhanced oil recovery with carbon dioxide geosequestration: first steps at Pre-salt in Brazil
Authors: Godoi José Maria Alves , dos Santos Matai Patrícia Helena Lara
Published: December 2021

This paper revisits the intense using of energy in the world and the role of the fossil fuels with predominance of the oil in the global primary energy supply and their effects to climate change. It also presents a new reading on the thermodynamic conditions and characteristics of CO2 and CO2-EOR together with oil industry advancement in the world and Brazil. The interface with chemical EOR processes involving nanoparticles (NPs), their application inside the reservoirs for EOR and understanding of fines migration reducing, among other physical phenomena is also studied. Carbon capture and storage (CCS) is a worldwide strategy for mitigating climate change. CO2 geosequestration is also analyzed on the leakage of CO2 and brine from aquifers and their implication to the security of the storage and environment. Recent studies show that, globally, CO2-EOR can extract up to 375 billion of additional oil barrels and geological storage up to 360 Gt of CO2 in the next 50 years. Pre-salt is a complex of microbial carbonate reservoirs with stromatolite framework in ultra-deep waters (1500–3000) m depth, underneath by thick salt layer (2000–2500) m. Its reservoirs are in the depth up to (5500–6500) m TVDSS and approximately (200–300) km offshore. It presents light oils and high (GOR) ranging (200–400) Sm3/Sm3 and huge CO2 contamination (8–15)%. Due to the large CO2 content of oil, this work investigated CO2-EOR and CO2 geosequestration within the reservoirs. Pilot test demonstrated that miscible CO2-EOR with WAG is feasible and beneficial to this hydrocarbon Province. This study also calculated and validated the potential of CO2-EOR to the CCS. It concludes that Pre-salt can contribute to recovery factor (RF) increasing about 5.7 billion of additional oil barrels, and to CCS with about 266 Mt CO2 to be geological stored, for the next 20 years. In this context, this work also analyses the recent changes on the Brazilian oil and gas regulation to encourage new international Companies to enter in Brazil and Pre-salt for petroleum exploring. In Pre-salt, CO2-EOR also connects the petroleum energy system to CCS, transforming the oil reservoir in a carbon sink. These results represent a substantial role of Pre-salt to the energy efficiency of energy resources recovering from the biosphere and a high contribution to the climate change mitigation.
Productivity evaluation of horizontal well in heterogeneous reservoir with composite water aquifer
Authors: Yuan Hui , Li Wenhong , Yuan Yingzhong , Luo Jiao , Yan Wende
Published: December 2021

Horizontal well is an important way to develop thin reservoir with edge-bottom water aquifer. For the horizontal well near oil–water contact, the reservoir have the features of edge water and bottom water at the same time. The productivity formula of horizontal well in pure edge water or pure bottom water reservoir is not fully applicable to this type of reservoir. For the heterogeneous reservoir with composite water aquifer, the horizontal well is divided into multiple well sections by using the concept of multi-segment well. Based on the seepage mechanics theory and potential superposition principle, considering the mutual interference between multi well sections, the productivity formula of horizontal well in heterogeneous reservoir with composite water aquifer is established. The new productivity formula considers the effect of reservoir heterogeneity, the quasi-linear flow of lateral edge water and the ellipsoidal flow of vertical bottom water. It can effectively determine the influence range and drainage distance of edge water in a heterogeneous reservoir with composite water aquifer. According to the test data of horizontal wells in Weizhou 11-1 oilfield, the drainage distancebof edge water is fitted and used to predict the productivity of new wells, and the result is very good. The research result lays a foundation for productivity prediction of horizontal well in heterogeneous reservoir with composite water aquifer.
Reservoir properties estimation from 3D seismic data in the Alose field using artificial intelligence
Authors: Ogbamikhumi A. , Ebeniro J. O.
Published: December 2021

In an attempt to reduce the errors and uncertainties associated with predicting reservoir properties for static modeling, seismic inversion was integrated with artificial neural network for improved porosity and water saturation prediction in the undrilled prospective area of the study field, where hydrocarbon presence had been confirmed. Two supervised neural network techniques (MLFN and PNN) were adopted in the feasibility study performed to predict reservoir properties, using P-impedance volumes generated from model-based inversion process as the major secondary constraint parameter. Results of the feasibility study for predicted porosity with PNN gave a better result than MLFN, when correlated with well porosity, with a correlation coefficient of 0.96 and 0.69, respectively. Validation of the prediction revealed a cross-validation correlation of 0.88 and 0.26, respectively, for both techniques, when a random transfer function derived from a given well is applied on other well locations. Prediction of water saturation using PNN also gave a better result than MLFN with correlation coefficient of 0.97 and 0.57 and cross-validation correlation coefficient of 0.89 and 0.3, respectively. Hence, PNN technique was adopted to predict both reservoir properties in the field. The porosity and water saturation predicted from seismic in the prospective area were 24–30% and 20–30%, respectively. This indicates the presence of good quality hydrocarbon bearing sand within the prospective region of the studied reservoir. As such, the results from the integrated techniques can be relied upon to predict and populate static models with very good representative subsurface reservoir properties for reserves estimation before and after drilling wells in the prospective zone of reservoirs.
Modeling research on the extreme hydraulic extension length of horizontal well: impact of formation properties, drilling bit and cutting parameters
Authors: Lu Nu , Zhang Bo , Wang Tao , Fu Qianming
Published: December 2021

Horizontal well can increase well productivity and improve the economic benefit, which significantly promotes the development of shale gas, tight oil and heavy oil. Moreover, it plays an important role in the development of natural gas hydrate. Horizontal extension ability is one of the key indexes of horizontal well, but it is always impacted by formation properties and well structure. Therefore, a model is established to analyze the impact of formation properties and well structure as comprehensive as possible, which considers not only traditional influencing factors, like formation pressure and drilling bit parameters, but also other key factors, including cutting particle size, wellbore diameter and cross section. Based on the analysis, some advises are proposed for field application. The analysis indicates that horizontal well has stronger extension ability in the formation with low formation pressure and high fracture pressure, but it is still limited by pump pressure. Under-balanced drilling can strength the extension ability in high formation pressure by reducing drilling mud density. The natural fractures in formation should be noted when drilling long horizontal well. The extension length increases and then decreases with the cutting particle size, so cutting particle has optimal size for the horizontal extension length, which can be adjusted by the rate of penetration and rotation speed. The extension length increases first and then decreases with the gap between drilling string and hole. Considering the demand of rock breaking and cutting sweeping around drilling bit, it is not recommended to adjust the drilling bit parameters. Both the cutting bed height and drilling string eccentricity have impact on horizontal extension length by changing minimum cutting-carry pump rate and annular pressure drop. Under different combinations of above two parameters, minimum cutting-carry pump rate and horizontal extension length are determined by different factors and can be divided into three parts, including acceptable cutting bed height, cutting lifting efficiency, pump pressure and total circulation pressure loss and well bottom pressure and formation fracture pressure. The findings of this study can help for better understanding of horizontal well hydraulic extension length and optimization method.
Geophysical appraisal for the sandy levels within Abu Roash C and E members in Abu Gharadig Field, Western Desert, Egypt
Authors: Sarhan Mohammad Abdelfattah
Published: December 2021

The present work concerns with the geophysical assessment for the sandstones of Abu Roash C and E members for being potential hydrocarbon reservoirs at Abu Gharadig Field, Western Desert, Egypt. The analysis of seismic data covers Abu Gharadig Field showing ENE–WSW anticline fragmented by NW–SE normal faults. The presence of these structures is due to the dextral wrench corridor that extensively deformed the north area of the Western Desert within Late Cretaceous episode. The examination of well-log data of Abu Gharadig-6 Well revealed that the favourable zone locates between depths 9665–9700 ft (zone I) within Abu Roash “C” Member. The second promising zone in Abu Gharadig-15 Well occurs between depths 9962–9973 ft (zone II) in Abu Roash “E” Member. The quantitative evaluation indicated that zone I has better reservoir quality than zone II since it is characterised by low shale volume (0.01), high effective porosity (0.22), low water saturation (0.14), low bulk volume of water (0.03), higher values of absolute permeability (113 mD), high relative permeability to oil and low water cut, whereas zone II has 0.13 shale volume, 0.16 effective porosity, 0.39 water saturation, 0.06 bulk volume of water, lower values of absolute permeability (27 mD), low relative permeability to oil and relatively high water cut. The obtained results recommended that the drilling efforts should be focused on the sandy levels within Abu Roash C Member (1st priority) and the sand levels within Abu Roash E Member (2nd priority) in Abu Gharadig Basin and its surroundings.
Evaluation of reservoir performance by waterflooding: case based on Lanea oilfield, Chad
Authors: Zene Mahamat Tahir Abdramane Mahamat , Hasan Nurul , Jiang Ruizhong , Zhenliang Guan , Abdullah Nurafiqah
Published: December 2021

The research of the current study is primarily focused on evaluating the reservoir performance by utilizing waterflood technique, based on a case study at Lanea oil field located in Chad; various mechanisms along with approaches were used in considering the best suitable pattern for waterflooding. All the simulation work was compared against a base case, where there was no involvement of water injection. Moreover, for the base case, a significant amount of oil left behind and cannot be swept, because of lower reservoir pressure at the downhill. The recovery factor obtained was in the range of 14.5–15% since 2010, and in order to enhance the oil production, an injection well was applied to boost the reservoir pressure; oil recovery is improved. In addition, sensitivity analysis study was performed to reach the optimum production behavior achieved by possible EOR method. Parameters, such as grid test, injection position, proper selection production location, permeability, and voidage substitution, were defined in the simulation study.
Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases
Authors: Bougre E. S. , Gamadi T. D.
Published: December 2021

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.
Characteristics of increasing displacement efficiency by surface-active polymer flooding for enhancing oil recovery
Authors: Yu Qiannan , Liu Yikun , Liang Shuang , Tan Shuai , Chen Chenghan , Sun Zhi , Yu Yang
Published: December 2021

Surface-active polymer is a novel multifunctional active polymer applied for enhancing oil recovery which has both viscosity-increasing ability and surface activity. Experiments were carried out to indicate basic physicochemical properties of surface-active polymer and to study on differences of properties between surface-active polymer and other chemical flooding agents, and characteristics of increasing displacement efficiency by surface-active polymer flooding have been tested. Experimental results show that the molecular aggregation conformation, viscosity performance and flow capacity of surface-active polymer were significantly different from those of other chemical flooding agents. Positive effects of viscosity and viscoelastic properties and improvements in interfacial chemical properties are basic characteristics of increasing displacement efficiency by surface-active polymer flooding which are basic principles of surface-active polymer flooding for enhancing oil recovery.
Geo-electrical investigation of the groundwater potential of Ogidi and environs, Anambra State, South-eastern Nigeria
Authors: Onyekwelu C. C. , Onwubuariri C. N. , Mgbeojedo T. I. , Al-Naimi L. S. , Ijeh B. I. , Agoha C. C.
Published: December 2021

The electrical resistivity method was used to determine the groundwater potential of Ogidi and its environs. Thirteen soundings were carried out at thirteen different locations using the ABEM terrameter (SAS 1000), and adopting the Schlumberger configuration with maximum current electrode spacing of 1000 m. The lithologic logs for the boreholes were used to delineate the geologic sections. The results revealed six to nine geo-electric layers comprising laterite, clayey sandstone, sandstone, water-saturated sandstone and shale. The water-saturated sandstone forms the aquiferous unit. This unit was found to have resistivity values ranging from 363Ωm to 9107Ωm. It is deeply seated in some areas with a depth of 33.2–103 m. It was observed that the hydraulic conductivity varies between 0.001 and 0.066 m/day, while the transmissivity values vary between 0.01 and 4.7 m2/day. Among all the VES points studied, it was observed that VES 1 has the highest transmissivity value and the highest aquifer thickness. In view of the foregoing, it is expected that water will flow more from aquifer in VES 1 since groundwater flow from an aquifer is directly proportional to transmissivity.
Application of particle swarm optimization and genetic algorithm for optimization of a southern Iranian oilfield
Authors: Razghandi Milad , Dehghan Aliakbar , Yousefzadeh Reza
Published: December 2021

Optimization of the placement and operational conditions of oil wells plays an important role in the development of the oilfields. Several automatic optimization algorithms have been used by different authors in recent years. However, different optimizers give different results depending on the nature of the problem. In the current study, a comparison between the genetic algorithm and particle swarm optimization algorithms was made to optimize the operational conditions of the injection and production wells and also to optimize the location of the injection wells in a southern Iranian oilfield. The current study was carried out with the principal purpose of evaluating and comparing the performance of the two most used optimization algorithms for field development optimization on real-field data. Also, a comparison was made between the results of sequential and simultaneous optimization of the decision variables. Net present value of the project was used as the objective function, and the two algorithms were compared in terms of the profitability incremental added to the project over twelve years. First, the production rate of the producers was optimized, and then water alternating gas injection wells were added to the field at locations determined by engineering judgment. Afterward, the location, injection rate, and water alternating gas ratio of the injectors were optimized sequentially using the two algorithms. Next, the production rate of the producers was optimized again. Finally, a simultaneous optimization was done in two manners to evaluate its effect on the optimization results: simultaneous optimization of the last two steps and simultaneous optimization of all decision variables. Results showed the positive effect of the algorithms on the profitability of the project and superiority of the particle swarm optimization over the genetic algorithm at every stage. Also, simultaneous optimization was beneficial at finiding better results compared to sequential optimization approach. In the end, a sensitivity analysis was made to specify the most influencing decision variable on the project’s profitability.
The novel technology for reservoir stimulation: in situ generation of carbon dioxide for the residual oil recovery
Authors: Panahov Geylani M. , Abbasov Eldar M. , Jiang Renqi
Published: December 2021

The gas and chemical flooding for reservoir stimulation with residual hydrocarbons reserves are highly relevant problem of current oil and gas recovery strategy. The objective of this paper is laboratory study and field implementation of new gas-EOR technology—in situ carbon dioxide generation technique for CO2-liquid slug formation under oil displacement, increasing the reservoir sweep efficiency and residual oil recovery. This paper presents a summary of a wide range of laboratory tests conducted on different core samples and chemical compositions. Several physical and hydrodynamic phenomena of in situ CO2generation in highly permeable zones of a porous medium have been investigated as a part of complex study, which involved laboratory tests on the field-scale industrial technology applications, determination of optimal concentrations of foaming agents and inhibiting additives in gas-releasing solutions, etc. The results of laboratory experiments showed that the incremental recovery ranged between 30 and 35% oil original in place. The unique results of the field implementation provide developing an optimal technological scheme of reservoir stimulation with residual oil reserves both onshore and offshore oil fields. Technology of in situ CO2generation was applied on the group of wells on Penglai offshore oil field (Bohai Bay). Incremental oil production for field operation was 37,740 bbl of crude oil. Theoretical and laboratory studies, as well as the outcomes of industrial implementation of a new method of residual oil recovery, using a CO2-slug confirm technology and economic profitability of the proposed solution.
Experimental investigation of proppant clustering in intersected fractures
Authors: Ma Wenpei , Tomac Ingrid
Published: December 2021

This paper investigates the dynamics of proppant agglomerations during flow and transport within fractures intersected at the angles typical for the joint of pre-existing and newly formed fractures. The study considers variations and coupling of fluid flow rates, proppant volumetric concentrations, fluid dynamic viscosities and fracture intersection angles. Proppants are widely used during hydraulic fracturing to keep fractures open and enhance reservoir permeability. This study uses plexiglas experimental slots and visual analysis for identifying particle displacements. Geo-Particle Image Velocimetry–Reliability-Guided (GeoPIV-RG) method tracks particle movements among images by comparing the reference and subsequent snapshots at the point and time of interest. Results of this study show that the proppant volumetric concentration and the fluid flow rate are closely correlated with each other for affecting proppant flow, transport, and agglomeration formation. Increasing the proppant volumetric concentration generally promotes particle agglomeration, with different extent when coupled with the fluid flow rate. Proppant volumetric concentration affects the size, shape, and distribution of particle clusters. Increasing the fluid flow rate increases the occurrence of particle agglomerates at low proppant volumetric concentration; however, this trend is absent under high proppant volumetric concentrations. Sizes and shapes of proppant agglomerates change as the fluid flow rate changes. Changes of fracture intersection angle minimally affect shape, size and distance between proppant agglomerates and clusters. Furthermore, increasing the fluid dynamic viscosity strongly promotes proppant agglomeration. Although fluid dynamic viscosity changes do not affect the shape and size of particle clusters, the distance between adjacent clusters decreases at higher fluid dynamic viscosity.
First evidence of the early cretaceous oceanic anoxic events (MBE and OAE1a) in the southern Tethyan margin (NE-Tunisia): biostratigraphy and shale resource system
Authors: Talbi Rachida , Amri Ahlem , Boujemaa Abdelhamid , Gabtni Hakim , Spiller Reginal , Levey Raymond
Published: December 2021

The Jebel Oust region (north-eastern Tunisia) recorded two levels of marine black shale in the Lower Cretaceous marly series. Geodynamic evolution, biostratigraphic and Rock–Eval analysies allow classifying those black shales as unconventional shale oil resource systems that were deposited during two oceanic anoxic events: the Middel Barremian Event "MBE" and the Early Aptian Event "OAE1a". Paleogeographic evolution highlights two transgressive–regressive cycles: the first one is Valanginian-Early Barremian, and the second is Late Barremian–Early Aptian. Each black shale deposit occurs at the end of the transgression that coincides with the highest sea level. During the Barreman–Aptian interval, sedimentation was controlled by extensional faults in a system of tilted fault blocks which were reactivated several times. Kerogen is of type I, II origin in black shales and of type III origin in marls. Tmax values indicate "oil window" stage. Average transformation ratio is around 67% and 82%, respectively, in the Lower Aptian and Middel Barremian source rock related to the relatively high thermal maturity degree due to the deep burial of the later. Estimated initial hydrocarbon generation potential is moderate to high. Oil saturation index records an "oil crossover" indicating expelled and migrated hydrocarbons from the organic-rich to the organic-poor facies. The petroleum system of the two mature source rocks with a high hydrocarbon generation potential enclose all elements characterizing a "shale oil hybrid system with a combination of juxtaposed organic-rich and organic-lean facies associated with open fractures".
Mitigation capacity of an eco-friendly locally sourced surfactant for gas hydrate inhibition in an offshore environment
Authors: Elechi Virtue Urunwo , Ikiensikimama Sunday Sunday , Ajienka Joseph Atubokiki , Akaranta Onyewuchi , Okon Okon Efiong
Published: December 2021

Gas hydrate inhibition is very key and has become more sensitive as oil and gas exploration goes into deeper terrains especially deep offshore as a result of technological advancement. Use of chemicals has been the most efficient and cost effective in these areas. These chemicals add to the cost of doing oil and gas business and also cause harm to the environment; hence, research has been going on for more eco-friendly and cost-efficient inhibitors. This study takes a look at a locally sourced surfactant as one of such inhibitors. Varying weight percentages of the LSS were screened in a locally fabricated laboratory mini flow loop of 39.4 m with an internal diameter of 0.5 inch mounted on an external frame work. The various pressure plots (pressure vs. time, change in pressure vs. time, initial and final pressures vs. time) show that the LSS used in very small percentages performed better than the synthetic inhibitor methanol (MeOH) used in higher weight percentage than the LSS. The final pressures for MeOH for 1–5 wt% were 104, 111, 123, 120 and 123 psi while those of the LSS were 115, 128, 125, 127 and 131 psi, respectively, for 0.01–0.05 wt%, respectively. This means that the system with LSS had more stable pressure values than those of MeOH. Similarly, the change in pressure at the end of 120 min for MeOH was 46, 39, 27, 30 and 27 psi against 35, 22, 25, 23 and 19 psi for LSS. This was an indication that more gas was used up in the system with MeOH than in the system with LSS. The mitigation capacity of the LSS in percentage was calculated to be 69.30, 80.71, 78.07, 79.82 and 83.3% for 0.01–0.05 wt% while MeOH had values of 59.65, 65.79, 76.32, 73.68 and 76.32% for 1–5 wt%, respectively. This showed that the LSS inhibited hydrates better than MeOH in all the weight percentages considered. There is need to harness and develop the LSS for gas hydrate mitigation because it performed better than MeOH which is a known toxicant to man, terrestrial and aquatic habitat.
Seismic expression of miocene carbonate platform and reservoir characterization through geophysical approach: application in central Luconia, offshore Malaysia
Authors: Bashir Yasir , Faisal Muhammad Amir , Biswas Ajay , Babasafari Amir abbas , Ali Syed Haroon , Imran Qazi Sohail , Siddiqui Numair Ahmed , Ehsan Muhsan
Published: December 2021

A substantial proportion of proven oil and gas reserves of the world is contained in the carbonate reservoir. It is estimated that about 60% of the world’s oil and 40% of gas reserves are confined in carbonate reservoirs. Exploration and development of hydrocarbons in carbonate reservoirs are much more challenging due to poor seismic imaging and reservoir heterogeneity caused by diagenetic changes. Evaluation of carbonate reservoirs has been a high priority for researchers and geoscientists working in the petroleum industry mainly due to the challenges presented by these highly heterogeneous reservoir rocks. It is essential for geoscientists, petrophysicists, and engineers to work together from initial phases of exploration and delineation of the pool through mature stages of production, to extract as much information as possible to produce maximum hydrocarbons from the field for the commercial viability of the project. In the absence of the well-log data, the properties are inferred from the inversion of seismic data alone. In oil and gas exploration and production industries, seismic inversion is proven as a tool for tracing the subsurface reservoir facies and their fluid contents. In this paper, seismic inversion demonstrates the understanding of lithology and includes the full band of frequency in our initial model to incorporate the detailed study about the basin for prospect evaluation. 3D seismic data along with the geological & petrophysical information and electrologs acquired from drilled wells are used for interpretation and inversion of seismic data to understand the reservoir geometry and facies variation including the distribution of intervening tight layers within the Miocene carbonate reservoir in the study area of Central Luconia. The out-come of the seismic post-stack inversion technique shows a better subsurface lithofacies and fluid distribution for delineation and detailed study of the reservoir.
Velocity anisotropy and trend in Niger Delta, Nigeria
Authors: Aniwetalu Emmanuel , Anakwuba Emmanuel , Ilechukwu Juliet
Published: December 2021

In geophysical data interpretation, matching the vertical velocity direction from seismic data with borehole-derived velocities is a challenging task because seismic-derived velocities are faster than borehole recorded velocities. This geophysical phenomenon is caused by velocity anisotropy. In this study, we used an empirical approach to estimate the degree of velocity anisotropy in the study area. The results showed that the delta anisotropy in sandstone beds varies from − 2.5% to 7.2% while most of them concentrate between 3.2% and 6.1%. The epsilon ranges between -6.4% and 9.3% while many of them concentrate between 3.2% and 7.2%. The gamma varies from − 6.3% to 7.3% while most of them concentrate between 1.2% and 5%. At shale beds, delta anisotropy varies from − 11.2% to 11.1% but most of them concentrate between 4.3% and 10.5%. The epsilon varies from − 7.2% to 14.5% while most of them concentrate between 4.5% and 10.5%. The gamma varies from 6.4% to 8.2% while majority of them concentrate between 2% and 5.3%. The results indicate that the study area is weakly to moderately anisotropic with shale beds having higher anisotropy values than sandstone beds. This probably results from preferential alignment of clay mineral orientations which also affect in situ velocity propagation. Three distinct velocity gradients (low, moderate and very high) were identified in the study area. These velocities vary erratically but showed northeast–southwest increase in velocities. Thus, the need to derive correction factors for individual wells for improved exploration success.
Numerical simulation of formation damage by drilling fluid in low permeability sandstone reservoirs
Authors: He Weiwei , Liu Zhiqiang
Published: December 2021

Understanding the formation damage surrounding the well during the drilling operation is the key to predict damage degree and protect the formation in oil/gas reserviors. Based on the core drainage results, we obtained an empirical relationship between the invasion volume of drilling fluid and permeability reduction of formation. Furthermore, the equation is incorporated into a commercial reservior numerical simulation simulator to characterize the behaviors of drilling fluid invasion process. The results show that, although the invasion depth in low permeability reservoirs is short with the range of 1.7–2.5 m, the effect on recovery factor is significant due to the narrow seepage area in the near fracture region. When considering the formation damage, the pressure in the near-fracture damage region drops sharply, leading to a three-stage shape in pressure distribution curve. In addition, we found that high viscosity and low density oil-based slurry and shorter soaking period are conducive to decrease the formation damage during drilling operation. This work reveals the fundamental mechanisms of formation damage in low permeability reservoirs, which is a theoretical basis in formulation drilling fluids and optimization operation parameters.
Banana peel and mango kernel-based polymers and their suitability in enhanced oil recovery
Authors: Fadairo Adesina , Adeyemi Gbadegesin , Temitope Ogunkunle , Kegang Ling , Vamegh Rasouli , Enuice David , Temitope Ilusemiti , Ayoo James
Published: December 2021

This study reports the extraction and performance evaluation of two bio-derived polymers for enhanced oil recovery applications. The oil displacement processes were conducted using six (6) unconsolidated sandstone core plugs. Reservoir permeability tester was used to simulate real reservoir conditions in order to evaluate the suitability of the formulated biopolymers for oil displacement applications at laboratory conditions. The experimental results indicate the effectiveness of the biopolymer solutions in enhanced oil recovery in terms of their superior incremental oil recoveries after conventional waterflood with percentage oil recovery of 30.9–39.3% for banana peel derived polymer and 40.6–50.8% for mango kernel derived polymer compared to conventional waterflood with percentage recovery of 16.2–32% of the initial oil in place. This work identified the potential suitability and use of bio-derived polymers for enhanced oil recovery applications with emphasis on their biodegradability.
Experimental study of shale drillability with different bedding inclinations under varying wellbore pressure conditions
Authors: Chen Shuai , Shi Xiangchao , Bao Heng , Gao Leiyu , Wu Jie
Published: December 2021

In the practice of shale gas development engineering, it is important to understand the physical and mechanical properties of shale. The bedding inclinations of shale are known to significantly influence its physical and mechanical properties. This study mainly examined the influence of bedding inclinations on drillability under different wellbore pressures. The bedding inclinations used in this study varied from 0° to 90°, with a gradient of 15°. The wellbore pressure values used varied from 0 to 25 MPa, with a gradient of 5 MPa. The results show that the drillability index of shale increases exponentially with increasing wellbore pressure at different bedding inclinations. The proposed exponential empirical model can describe the relationship between the drillability index and wellbore pressure. When the wellbore pressure is less than 15 MPa, bedding inclinations significantly influence the drillability index, and the drillability index of shale shows a “W”-type variation trend as the bedding inclinations increase in the range of 0° to 90°. The influence of bedding inclinations on drillability decreases gradually with increasing wellbore pressure. When the wellbore pressure increases to 25 MPa, the impact of bedding inclinations on drillability is virtually undetectable. The results of this study can provide reasonably insight into the effect of bedding inclinations on shale deformation under the drill bit, and useful prediction for the drillability index under in situ conditions.
Integrated rock typing and pore facies analyses in a heterogeneous carbonate for saturation height modelling, a case study from Fahliyan Formation, the Persian Gulf
Authors: Ranjbar-Karami Rasoul , Tavoosi Iraj Parisa , Mehrabi Hamzeh
Published: December 2021

Knowledge of initial fluids saturation has great importance in hydrocarbon reservoir analysis and modelling. Distribution of initial water saturation (Swi) in 3D models dictates the original oil in place (STOIIP), which consequently influences reserve estimation and dynamic modelling. Calculation of initial water saturation in heterogeneous carbonate reservoirs always is a challenging task, because these reservoirs have complex depositional and diagenetic history with a complex pore network. This paper aims to model the initial water saturation in a pore facies framework, in a heterogeneous carbonate reservoir. Petrographic studies were accomplished to define depositional facies, diagenetic features and pore types. Accordingly, isolated pores are dominant in the upper parts, while the lower intervals contain more interconnected interparticle pore types. Generally, in the upper and middle parts of the reservoir, diagenetic alterations such as cementation and compaction decreased the primary reservoir potential. However, in the lower interval, which mainly includes high-energy shoal facies, high reservoir quality was formed by primary interparticle pores and secondary dissolution moulds and vugs. Using huge number of primary drainage mercury injection capillary pressure tests, we evaluate the ability of FZI, r35Winland, r35Pittman, FZI* and Lucia’s petrophysical classes in definition of rock types. Results show that recently introduced rock typing method is an efficient way to classify samples into petrophysical rock types with same pore characteristics. Moreover, as in this study MICP data were available from every one meter of reservoir interval, results show that using FZI* method much more representative sample can be selected for SCAL laboratory tests, in case of limitation in number of SCAL tests samples. Integration of petrographic analyses with routine (RCAL) and special (SCAL) core data resulted in recognition of four pore facies in the studied reservoir. Finally, in order to model initial water saturation, capillary pressure data were averaged in each pore facies which was defined by FZI* method and using a nonlinear curve fitting approach, fitting parameters (M and C) were extracted. Finally, relationship between fitting parameters and porosity in core samples was used to model initial water saturation in wells and between wells. As permeability prediction and reservoir rock typing are challenging tasks, findings of this study help to model initial water saturation using log-derived porosity.
Evaluation of environment friendly micro-ionized litchi leaves powder (LLP) as a fluid loss control agent in water-based drilling fluid
Authors: Prakash Ved , Sharma Neetu , Bhattacharya Munmun , Raina Ashok , Gusain Man Mohan , Sharma Kiran
Published: December 2021

This work investigates the efficacy of a biodegradable natural product, litchi leaves powder (LLP) as a filtration loss control agent in the water-based drilling fluid formulations. In order to evaluate the potential of litchi leaves powder (LLP), a strict protocol of experimentations according to API (American Petroleum Institute) standard has been followed. The experimental outcome showed that before hot rolling and after hot rolling of mud samples at 100 °C it was observed that 3–5% Concentration of LLP significantly increased the rheological parameters such as PV, YP and gelation of drilling fluid as compared to reference mud. Also, LLP reformed the filtration loss control characterization, suggesting a better biodegradable fluid loss reducing agent. After hot rolling at 100 °C for 18 h, the water-based drilling fluid with LLP as an additive showed a marked reduction in filtration control property as compared to reference Mud (RM). Experimental results concluded that 5% concentration of LLP significantly reduced the filtration loss of drilling fluid by 70.6% as compared to reference mud under the influence of 100 psi pressure. However, the conventional fluid loss additive CMC (LVG) reduced the filtration loss by maximum 67.5% as compared to reference mud. Therefore, LLP can be used as an alternative to CMC (LVG) in water-based drilling fluid with a maximum subsurface temperature of 100 °C.
Well integrity management in mature fields: a state-of-the-art review on the system structure and maturity
Authors: Yakoot Mostafa S. , Elgibaly Ahmed A. , Ragab Adel M. S. , Mahmoud Omar
Published: December 2021

Nowadays, oil and gas (O&G) fields are maturing and creating new threats. This urged the operating companies and industry researchers to have intensive focus on well integrity (WI). Building Well Integrity Management System (WIMS) establishes standardized criteria to guarantee that integrity of all wells is preserved during their lifespan, functions properly in healthy condition, and is able to operate consistently to fulfill the expected production/injection demands. Moreover, exploration and production (E&P) companies put Health, Safety, and Environment (HSE), assets, production, local and public image as top priority in their businesses. Having effective WIMS at all times and throughout all well phases reduces the frequency of major integrity failures and thus helps companies to be on track regarding the aforementioned considerations. In this paper, we present a comprehensive review on the system structure and maturity of WIMS in mature fields. This state-of-the-art review highlights the efforts made by different O&G operators all over the world to develop and start application of WIMS, which varies widely due to differences in the main WI challenges that are recurring in each field or concession. Moreover, it lists the goals and expounds the stages of launching effective WIMS. In addition, the key elements, around which the WI program is structured, are discussed and presented for various O&G operators. The major five elements of accountability and responsibility, well operations procedures, well intervention procedures, tubing and casing integrity program, and wellhead and X-tree maintenance are overviewed. Furthermore, this paper assesses WIMS sustainability through demonstration of WI maturity models, scrutiny of maturity levels, and analysis of transformative elements to convert WIMS into strategic framework. Risk management systems as well as application of analytics in WIMS are also covered and thoroughly discussed. In reviewing the literature covering different assets—all over the world for the last 15 years—it was found that real progress was made in WI area, and WIMS established in many operating companies through different approaches. However, the introduced systems lack universality and few of them are applying artificial intelligence as powerful tool for boosting the system. The most obvious finding to emerge from the analysis is that WIMS is crucial system that must be implemented and matured for well lifecycle. The findings of this study can help operating companies for better framing of key pillars to have robust and operable WIMS throughout different fields and concessions, hence improving the well integrity performance worldwide.
Proximity politics in changing oceans
Authors: Foley Paul
Published: December 2021

How will ocean governance actors and institutions handle a future where the abundance and spatial distribution of marine life changes rapidly and variably? The answer, this paper argues, will be influenced by inherited and changingocean proximity politics, whereby institutions and actors use spatial proximity or adjacency to legitimize particular forms of resource control, conservation and use. Focusing on United Nations and Canadian institutional contexts and recognizing state and non-state actors as agents of policy change, the paper documents and examines why and how spatial proximity has been invoked (i) as a principle for claiming, defining and implementing use rights, privileges and responsibilities for not just nation-states but also for other entities such as coastal communities and small-scale fisheries; (ii) to justify and legitimize rights, privileges and responsibilities for their interest and benefit; and (iii) to inform and challenge global and local discussions about principles such as conservation, sustainability and distributive equity. The future practical use of spatial closeness/distance for guiding policies of access and exclusion under conditions of change will likely be influenced by challenges associated with applying multiple and conflicting governance principles, accommodating diverse interests and interpretations of principle definition and application, and multiple forms of biophysical and social mobilities. The conclusion highlights four areas of further research and policy engagement for the study of ocean proximity politics.