bluuebunny/crossref_metadata_2025_split huggingface dataset:
Underbalanced MPD Technology Proved to be Effective in Drilling of Fractured Granitic Basement
Authors: Chen Peng , Wang Xi , Wu Meng 
Published: February 2021

Abstract
The basement hydrocarbon reservoirs have been discovered in a lot of places over the world. The remarkable characteristics of the basement reservoirs are their low pressure with narrow density windows and well developed fractures which usually resulted in probably massive losses. A case study on drilling of fractured granitic basement with application of UBD in Chad and MPD in Indonesia is presented in this paper.
To tackle the common problems of drilling in narrow density windows and potential problem of losses, an underbalanced drilling (UBD) technology with a micro-foam drilling fluid was used in Chad. The pore pressure coefficient of the basement of Chad was predicted as between 1.02-1.06, and the density of the micro-foam drilling fluid was designed to be 8.7ppg. While an under-balanced managed pressure drilling (MPD) technology with a synthetic based gas-to-liquid (GTL) drilling fluid was utilized in Indonesia. The formation pressure coefficient of the basement of Indonesia was estimated to be 1.04, and the density of the GTL drilling fluid was designed to be 7.4ppg.
Losses or severe losses existed in previous conventional near-balanced drilling in fractured granitic basement of buried hills of Chad. The problem of losses also encountered even UBD was later used. Losses and kicks continued almost all the time during drilling, coring and wireline logging in some wells. Losses happened as soon as pump started while overflow occurred no sooner than pump stopped. However, the potential problem of losses and kicks was completely controlled by utilization of under-balanced MPD technology in fractured granitic basement of Indonesia.
The under-balanced MPD technology, a precisely pressure controlled drilling system, is able to accurately control the annular pressure profile throughout the wellbore, therefore it could effectively achieve safe drilling in narrow density window and cut non-production time. It is proved to be effective in drilling of fractured granitic basement.
Novel Method for Real-Time Monitoring of Scale Control Products at the Site of Use
Authors: Johnstone James , Toivonen Susanna , Griffin Rick , O'Brien Ashleigh , Mundill Paul , Siivonen Joonas , Väisänen Pave , Tiittanen Satu , Lehmusto Mirva , Härmä Harri , Hänninen Pekka , Teimonen Timo 
Published: February 2021

Abstract
Scale inhibitors are used extensively in the oil and gas industry to provide the level of flow assurance required to maximise safe and economic hydrocarbon production. For both continuous and scale squeeze treatments, residual inhibitor concentrations need to be verified on a continual basis to assure the field operator that the implemented scale management program remains effective. To date, the analytical work required to verify residual inhibitor levels of the majority of scale inhibitor chemistries needs to be carried out onshore in a suitably equipped analytical laboratory. Often the time delay from sample collection to reporting of analytical results introduces a significant level of uncertainty with regard to effective scale control which, if removed, would substantially improve the production assurance and safety of the facility operations.
The Residual Monitoring and Analysis system is a point-of-use monitoring platform designed to measure the residual concentration of polymeric scale inhibitors with average molecular weight less than 10 000 Da in produced water, providing a timely and accurate residual scale inhibitor concentration to the facility operator. The analysis procedure can be carried out at the production location where the sample is taken, with the result obtained and recorded within 30minutes or less. The analysis method is unaffected by either the presence of other production chemicals or by the variation in typical North Sea produced water composition.
The measurement system utilises the Aqsens aqueous liquid fingerprinting technology platform (Hänninen et al. 2013) and can be designed to work with a wide range of scale inhibitor chemistries; a specific tag/label is not necessary. Unlike other systems, the analytical method is not based on immunoassay detection technology that requires modification of the scale inhibitor formulation to include tagged polymer-specific antibodies. We have deliberately reverse engineered this for a range of current scale inhibitor products to provide direct field analysis to customers on either continuous or scale squeeze application programs.
The system derives its sensitivity by combining time-resolved fluorescence with carefully optimised chemistries to quantify the product for scale inhibition levels. Performance results from laboratory testing and coreflood experiments will be presented.
Characterization of Unconventional Reservoir for Development and Production: An Integrated Approach
Authors: Pal Omprakash , Zoghbi Bilal , Razzaq Waseem Abdul 
Published: February 2021

Abstract
Unconventional reservoir exploration and development activities in the Middle East have increased and are expected to continue to do so. National oil companies in the Middle East have a strategy for maximizing oil exports as well as use of natural gas. This has placed emphasis on use of advanced technology to extend the lives of conventional reservoirs and more activities in terms of “unconventional gas and oil.” Understanding unconventional environments, such as shale reservoirs, requires unique processes and technologies based on reservoir properties for optimum reservoir production and well life.
The objective of this study is to provide the systematic work flow to characterize unconventional reservoir formation. This paper discusses detailed laboratory testing to determine geochemical, rock mechanical, and formation fluid properties for reservoir development. Each test is described in addition to its importance to the reservoir study. Geochemical properties, such as total organic carbon (TOC) content to evaluate potential candidates for hydrocarbon, mineralogy to determine the formation type and clay content, and kerogen typing for reservoir maturity. Formation fluid sensitivity, such as acid solubility testing of the formation, capillary suction time testing, and Brinell hardness testing, are characterized to better understand the interaction of various fluids with the formation to help optimize well development.
An additional parameter in unconventional reservoirs is to plan ahead when implementing the proper fracturing stimulation technique and treatment design, which requires determining the geomechanical properties of the reservoir as well as the fluid to be used for stimulation. Properties of each reservoir are unique and require unique approaches to design and conduct fracturing solutions. The importance of geomechanical properties is discussed here.
This paper can be used to help operators obtain a broad overview of the reservoir to determine the best completion and stimulation approaches for unconventional development.
Required Understanding for the Development of Shale Reservoirs in the Middle East in Light of Developments in North America
Authors: Sayed Mohammed A. , Al-Muntasheri Ghaithan A. , Liang Feng 
Published: February 2021

Abstract
The ever-increasing international energy demands require exploration of new fossil energy resources. Unconventional oil and gas have received a great deal of attention in recent years as the technological advancements have made their production possible and more economical. Most of the shale developments took place in North America where the learning curve is being developed. Although shales still require lots of understanding and more advanced technologies, a substantial experience has been developed in North America. This paper presents an effort to summarize the current experience in shales of North America from different angles: rock mechanics, rock/fluids interaction, gas flow mechanisms through shale rocks, proppant embedment and water recovery after shale fracturing.
Three prospective areas for unconventional gas were found in the Kingdom of Saudi Arabia: in the Northwest, South Ghawar and condensate-rich shale gas in the Rub' Al-Khali area. The main targeted formations for unconventional natural gas are: the Ordovician Sarah, Silurian Qulibah, Qusaiba hot shale, Devonian Jauf and Permian Unayzah formations. The Qusaiba shale is located at depths of 7,500 to 20,000 ft throughout Saudi Arabia's basins. The Qusaiba Hot Shale in the Northwest area is relatively thick and it is considered to be the richest in all possible source rocks with a maximum total organic content of 6.15%.
Shales are composed of: kerogen, rock matrix and natural fractures. The mineralogy of shale varies from one field to another. Literature has confirmed that for Haynesville shale, the rock becomes more ductile with the increase in its clay content. Similar trends were seen for Lower Bakken shale. While other shale reservoirs, like Eagle Ford, Barnett and Middle Bakken are harder since they contain more quartz and calcite. The exposure of these clay-sensitive rocks to fracturing fluids does change their rock mechanical properties. This has been confirmed in literature where Middle Bakken shale lost 52% of its Young's modulus after exposure to 2 wt% KCl slickwater at 300°F for 48 hours.
The use of slickwater in fracturing represents a major challenge as it consumes huge volumes of this valuable resource. Recycling of produced water has been attempted in North America in Marcellus. An average amount of 3 to 8 million gallons of water are used in fracturing one well in Marcellus shale formation. In one application, re-use of the flowback water resulted in 25% reduction in the fresh water volumes and it reduced the cost of disposing produced water by 45 to 55%. The paper presents a summary of all of these findings from North America. A comprehensive understanding and analysis on unconventional reservoirs is required for the Middle Eastern reservoirs.
Predicting Hydraulic Fracturing in a Carbonate Gas Reservoir in Abu Dhabi Using 1D Mechanical Earth Model: Uncertainty and Constraints
Authors: Sirat Manhal , Ahmed Mujahed , Zhang Xing 
Published: February 2021

Abstract
In-situ stress state plays an important role in controlling fracture growth and containment in hydraulic fracturing managements. It is evident that the mechanical properties, existing stress regime and the natural fracture network of its reservoir rocks and the surrounding formations mainly control the geometry, size and containments of produced hydraulic fractures. Furthermore, the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with corresponding stress regimes at different depths. Hence predicting the hydro-fractures can be theoretically achieved once all the above data are available. This is particularly difficult in unconventional and tight carbonate reservoirs, where heterogeneity and highly stress variation, in terms of magnitude and orientation, are expected.
To optimize the field development plan (FDP) of a tight carbonate gas reservoir in Abu Dhabi, 1D Mechanical Earth Models (MEMs), involving generating the three principal in-situ stresses' profiles and mechanical property characterization with depth, have been constructed for four vertical wells. The results reveal the swap of stress magnitudes at different mechanical layers, which controls the dimension and orientation of the produced hydro-fractures. Predicted containment of the Hydro-fractures within the specific zones is likely with inevitable high uncertainty when the stress contrast between Sv, SHmax with Shmin respectively as well as Young's modulus and Poisson's Ratio variations cannot be estimated accurately.
The uncertainty associated with this analysis is mainly related to the lacking of the calibration of the stress profiles of the 1D MEMs with minifrac and/or XLOT data, and both mechanical and elastic properties with rock mechanic testing results. This study investigates the uncertainty in predicting hydraulic fracture containment due to lacking such calibration, which highlights that a complete suite of data, including calibration of 1D MEMs, is crucial in hydraulic fracture treatment.
Fracture Identification and Comprehensive Evaluation of the Parameters by Dual Laterolog Data
Authors: Saboorian-Jooybari H.. , Dejam M.. , Chen Z.. , Pourafshary P.. 
Published: February 2021

Abstract
Quality and productivity of tight formations are heavily dependent on the degree of fracture development. In fact, hard and dense carbonate formations may not be considered as net pay without presence of fractures which conduct fluids towards wellbore. The evaluation of fractures is a key to reservoir effectiveness characterization for well drilling, completion, development and simulation of fractured reservoirs. Although new imaging technologies such as Formation Micro-Scanners and Imagers (FMS and FMI) provide the information of fracture properties (dip angle, porosity, aperture and permeability), image logs are very expensive and cannot be available in all wells. In this paper, fracture parameters are estimated using conventional Dual Laterolog (DLL) resistivity, which includes shallow (LLS) and deep (LLD) responses. This technique is based on electrical resistivity anomalies because of separation of shallow and deep laterolog curves. Fracture parameters that can be calculated by DLL include dip angle, aperture, porosity, permeability and cementation factor. The accuracy of the calculated parameters using DLL is validated by the results of FMI in one well in one of Iranian fractured reservoirs. Despite the image logs, the conventional DLL is routinely run in all of the drilled wells. This makes the constructed fracture model on the basis of DLLs more reliable than the corresponding model founded on limited and insufficient image logs. Furthermore, DLL has an advantage of much deeper evaluation of fractures in comparison with the immediate borehole investigation of image logs.
Non-Darcy Flow Effect in Fractured Tight Reservoirs: How Significant Is It at Low Flow Rates and Away from Wellbores?
Authors: Saboorian-Jooybari Hadi , Pourafshary Peyman 
Published: February 2021

Abstract
Reservoir development is increasingly moving towards unconventional resources such as tight reservoirs due to the rapid decline in conventional reserves. Several researches have been done in the petroleum industry addressing significant influence of non-Darcy flow behavior on well deliverability and reservoir performance. In all of the previous works, it is generally believed that the non-Darcy flow in a reservoir, if occurs, becomes considerable within a few feet around the wellbores beyond which it is negligible. Furthermore, when mentioned non-Darcy effect in the literature, attentions are usually attracted to gas wells with high production rates (i.e. rates higher than 10 MMSCF / day).
In this paper, correlations that are typically used for determination of non-Darcy coefficient are reviewed. Then, it is shown that the correlations are distinct and lead to considerably different values of the non-Darcy coefficient for the same rock sample. A simple guideline is also presented for choosing the most appropriate correlation for a reservoir. Main body of this paper is directed at accurate description of non-Darcy flow in fractured tight reservoirs. This study evaluates the validity of a widely accepted assumption, which considers non-Darcy effect significant only within a few feet around wellbore of gas wells producing at high rates. A synthetic simulation model is made using the data of a well from one of the Iranian fractured tight reservoirs. A full feature compositional simulator is used for the computations in this study. The distance out of the wellbore is subdivided into a number of regions, and then the necessity of including the non-Darcy component in each of the regions for better performance predictions is investigated. The effect of accounting the non-Darcy term in each of the regions on the simulation results such as production rate, final recovery and pressure behavior is studied. Furthermore, three distinct reservoir fluid types including dry gas, gas condensate and black oil are used with the objective well model to evaluate dependence of non-Darcy effect on the type of flowing fluid. The study results are used to provide guidelines about the necessity of global consideration of the non-Darcy term in simulation of different fluid systems even at low production rates. The results highlight that contribution of the non-Darcy component to flow can be significant even far away from wellbores, thus it must be considered globally in the bulk of reservoirs. Additionally, the study demonstrates that the role of non-Darcy component can be crucial even at low production rates regardless of reservoir fluid type. Therefore, in order to have accurate modeling, design and successful implementation of projects, simulations of fractured tight reservoirs must be performed with the global inclusion of the non-Darcy flow formulations regardless of the type of flowing stream and levels of production rate.
Unconventional Shale Play in Oman: Preliminary Assessment of the Shale Oil / Shale Gas Potential of the Silurian Hot Shale of the Southern Rub al-Khali Basin
Authors: Madi Jamal A. , Belhadj Elhadi M. 
Published: February 2021

AbstractOman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2).The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells).The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous.Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale.Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively.To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2.Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.
Impact of Geomechanics on Well Completion and Asset Development in the Bakken Formation
Authors: Ganpule Sameer , Srinivasan Karthik , Izykowski Tyler , Luneau Barbara , Gomez Ernest 
Published: February 2021

Abstract
In-situ stress variability within a reservoir is a primary parameter that controls hydraulic fracture initiation, growth, connectivity, and ultimately drainage and well spacing. This paper highlights the importance of characterizing the variability of in-situ stress and demonstrates the risk of underestimating stimulation treatment size when a treatment design is applied in a “copy-paste” fashion without any modifications to account for variation in pore pressure and in-situ stress across a basin. Thermal maturity and hydrocarbon generation from unconventional shales has a direct effect on pore pressure and the in-situ stress distribution in reservoir and barrier rocks. An examination of the Bakken Petroleum System (BPS) identifies regions of thermal maturity and higher pore pressure due to hydrocarbon expulsion. Consequently, the elevated pore pressure and the resulting in-situ stress vary vertically and laterally within the basin.
Multiple pore pressure profiles and corresponding stress profiles across the BPS were considered to quantify the impact of in-situ stress variability on hydraulic fracture geometry. These profiles include effects of normal pore pressure regime, over-pressure regime or pressure profiles transitioning from over pressure to normal pressure regimes. For a given stress profile, hydraulic fracture geometries are estimated using a fracture simulator, with multiple calibration points. The hydraulic fracture system and reservoir interactions are simulated in a subsequent production modeling phase which estimates drainage area characteristics, recovery forecasts and optimum well spacing for developing an asset.
Results from stress profile sensitivity emphasize the need to address variability of in-situ stress as it directly impacts well spacing considerations in an asset development plan. For example, stress profile with a normal pore pressure regime results in longer hydraulic fracture lengths in the Middle Bakken (MB) thus requiring three wells per section to infill the asset. Conversely, stress profile with over-pressure regime in MB results in much shorter hydraulic fracture lengths thus requiring more than three wells per section to develop the asset. Incorrectly assuming overpressure in a normally pressured zone could lead to over-engineering of wells and unnecessary costs, whereas incorrectly assuming normal pressure in zones that are in fact overpressured could lead to sub-optimal completions and/or a reduction in overall production.