Accessibility of Pores to Methane in New Albany Shale Samples of Varying Maturity Determined Using SANS and USANS

The accessibility of pores to methane has been investigated in Devonian New Albany Shale Formation early-mature (Ro = 0.50%) to post-mature (Ro = 1.40%) samples. A Marcellus Shale Formation sample was included to expand the maturation range to Ro 2.50%. These are organic matter-rich rocks with total organic carbon (TOC) values of 3.4 to 14.4% and porosity values of 2.19 to 6.88%. Contrast matching small-angle neutron scattering (SANS) and ultra-small angle neutron scattering (USANS) techniques were used to generate porosity-related data before and after pressure cycling under hydrostatic (in a vacuum and at 500 bar of deuterated methane) and uniaxial stress (0 to ca. 350 bar) conditions. Our results showed that the accessible porosity was small for the samples studied, ranging from zero to 2.9%. No correlation between the accessible porosity and TOC or mineralogical composition was revealed, and the most likely explanation for porosity variation was related to the thermal transformation of organic matter and hydrocarbon generation. Pressure caused improvements in accessible porosity for most samples, except the oil window sample (Ro = 0.84%). Our data show that densification of methane occurs in nanopores, generally starting at diameters smaller than 20 nm, and that the distribution of methane density is affected by pressure cycling.

Step Change in Delivering High Fracture Wells by Eliminating Expandable Liner

This paper discusses the journey of finding alternate solution for having to run the Expandable Liners operations in the Fahud field which is already one of the most operationally challenging fields to drill in Petroleum Development Oman (PDO), due to the presence of a gas cap in highly fractured and depleted limestone formations with total losses and the need for dynamic annulus fill to maintain primary well control. In Fahud field, there is a highly reactive shale formation within reservoir limestone formation. Due to high likelihood of total losses, this shale formation caused bore hole instability challenges while drilling. And with more depletion took place, the challenges became more frequently to occurred. In 2001, expandable tubular liner was introduced to address these bore hole instability challenges while drilling highly reactive shale formation under total losses in the 8-1/2″ section. The use of expandable technology was sustained over the years in delivering all wells drilled to traverse this reactive shale column. Previously before 2001, wells used to have fat well design by installations of extra casing to cover the formations and problematic zones. Also, Fahud field was not depleted as it is now, and the problematic shale zone used to drill by normal conventional way without any issue using inhibition frilling fluid. Petroleum Development Oman (PDO) identified expandable liner as a preferred alternative to ‘Fat’ well design. The ‘Fat’ well design would have a large hole size through potential loss zones, resulting in unmanageable volumes of water being required. Expandable liber was fast-tracked - various technical options were considered by PDO with expandable liner technology being identified as the best solution to address the problem of the shale column. However, the deployment of expandable tubular liner technology supported to drill & deliver wells but also has its associated challenges incurring additional time and cost with reasonable installation and low operations success rate due to number of operational steps required prior and after the expandable liner. Adding to that, all the challenges associated with each step. The installation of the expandable liner required eight operational steps with multiple trips to under-ream, install and expand, cement, caliper log and drill through the liner which increased the probability of something going wrong due to mainly the challenging well profile and multiple operations steps. The expandable liners technology was required when the target formation was below the reactive shale interval. The team carried out a study of previous deployments with the intention of identifying well planning and operational contributors to the installation difficulties and operations failures, with a view of eliminating the need for installing the expandable liner and drilling the well to the desired landing point at designed section total depth. Most of the unsuccessful installation rates were observed to be prevalent in wells with high angle applications. The team also observed that the length of the hole interval below the reactive shale column contributed to the number of unsuccessful installation and operational failure rates recorded. The team evaluated the impact of reducing well inclination on the ability to deliver the hole section without installing the expandable liner. Subsequently the team developed an optimization plan which involved keeping all build activities above and below the problematic interval and holding tangent at less than 45° inclination while drilling across the problematic shale. In conclusion, in 2020 the team delivered six wells (90% of wells crossing reactive shale formation delivered) using the above described approach and traversed the historically highly reactive shale formation without installing expandable liners. This resulted in a 20% reduction in total well construction time and 17% reduction in total well delivery cost per well. In addition to the time and cost saving, with the new approach, described in this paper, less water needed to be pumped for dynamic fill. This allowed bringing the wells quicker to production, thus reducing oil deferment.

Value of Cement Bond Logs for Evaluation and Improvement of Cementing Practices in Extended Reach Drilling ERD Wells

This paper discusses the value of cement logs as the core input to analyze the cement quality and validate the improvements made to cementing designs and practices of the intermediate casing string in Extended-Reach Drilling (ERD) wells. The ERD wells are being drilled from artificial islands in a field offshore in the UAE. The primary cementing objectives are isolating the reservoirs from their sublayers and protecting the casing against possible future corrosion across an upper formation. Cementing challenges include higher angle deviation, higher mud weight requirements resulting from an anisotropic, unstable shale formation present above the reservoir section. Effective reservoir management requires sound zonal isolation to eliminate crossflow between different reservoir units. In combination with standard cement bond logs (CBL), ultrasonic technology has provided detailed information about cement quality and a qualitative indication of casing position in the borehole. These have also led to valuable insight into how continued cementing designs and practices improved zonal isolation. Improvements in cement quality seen as a result of enhanced casing centralization, optimized hydraulic model, modified cement rheology, displacement rate impact, among others, were confirmed with the cement log evaluation program. The paper will present the ultrasonic and standard CBL responses, which support the enhancements made to the cementing design and practices that yield the desired results. The cement quality has been improved in the ERD wells intermediate section through strategic modification in cementing practices. Cement evaluation logs have played a significant role in validating the cementing methods’ development. Consistently improved zonal isolation results have opened up the opportunity for future efficiency gains by eliminating routine CBL.

Application of Okra Mucilage for the Prevention of Shale Swelling

Maintain wellbore stability is a very critical aspect of the drilling operation. The unstable wellbore provides severe loss to the drilling operators in terms of time and money. One of the significant reasons for unstable wellbore occurs due to the expansion of shale formation. Several solutions are utilized to tackle the expansion of shales, such as salts, PHPA, silicates, and oil-based drilling fluids. There are limitations associated with these solutions, such as thermal instability, limited supply, unfriendly to the environment and marine life, etc. In this study, Okra mucilage has been introduced as a shale swelling inhibitor in drilling fluids. Okra is widely used in the medical and food industries as a viscosifier as it is abundantly available in tropical and subtropical regions. Okra powder has been used as a fluid loss control additive in the literature. The application of the Okra solution as a shale swelling inhibitor in drilling fluids was not investigated in the past. In this study, Okra mucilage was extracted from the Okra plant and used as shale swelling inhibitor. Three different concentrations (5, 10 & 20) vol% of Okra mucilage mixed solutions were used for linear swell test. The test was performed using a linear swell tester at atmospheric conditions for 24 hours on bentonite wafers. Further zeta potential, particles size and capillary suction timer test (CST) were conducted. The experimental study revealed that Okra mucilage reduced the swelling of bentonite. For instance, 10 and 20% of Okra mucilage solutions reduced the swelling by 36.8% and 50.5%, respectively. The Okra mucilage decreased the zeta potential of clay and increased its particle size. CST time decreased initial at low concentration and increased with concentration. Overall, experimental investigations suggested that Okra mucilage could be an alternate green shale inhibitor in drilling fluids without compromising other drilling fluids' properties.

Optimize Internal Phase Salinity to Improve Wellbore Stability and Mitigate Lost Circulation

Wellbore instability and lost circulation are two major sources of non-productive time (NPT) in drilling operations worldwide. Non-aqueous fluid (NAF) is often chosen to mitigate this and minimize the chemical effect on wellbore instability in reactive shales. However, it may inadvertently increase the risk of losses. A simple method to optimize internal phase salinity (IPS) of NAF is presented to improve wellbore stability and mitigate the increased possibility of losses. Field cases are used to demonstrate the effects of salinity on wellbore instability and losses, and the application of the proposed method. IPS is optimized by managing bidirectional water movement between the NAF and shale formation via semi-permeable membrane. Typically, higher shale dehydration is designed for shallow reactive shale formation with high water content. Whereas, low or no dehydration is desired for deep naturally fractured or faulted formation by balancing osmotic pressure with hydrostatic pressure difference between mud pressure and pore pressure. The simple approach to managing this is as follows: The water activity profile for the shale formation (aw,shale) is developed based on geomechanical and geothermal information The water activity of drilling fluid (aw,mud) is defined through considering IPS and thermal effects The IPS of NAF is manipulated to manage whether shale dehydration is a requirement or should be avoided If the main challenge is wellbore instability in a chemically reactive shale, then the IPS should be higher than the equivalent salinity of shale formation (or aw,shale > aw, mud) If the main challenge is losses into non-reactive, competent but naturally fractured or faulted shale, then IPS should be at near balance with the formation equivalent salinity (or aw, shale ≈ aw, mud) It is important that salt (e.g. calcium chloride – CaCl2) addition during drilling operations is done judiciously. The real time monitoring of salinity variations, CaCl2 addition, water evaporation, electric stability (ES), cuttings/cavings etc. will help determine if extra salt is required. The myth of the negative effects of IPS on wellbore instability and lost circulation is dispelled by analyzing the field data. The traditional Chinese philosophy: "following Nature is the only criteria to judge if something is right" can be applied in this instance of IPS optimization. A simple and intuitive method to manage IPS is proposed to improve drilling performance.

Magmatic-Hydrothermal Processes of Vein-Type Haman-Gunbuk-Daejang Copper Deposits in the Gyeongnam Metallogenic Belt in South Korea

Haman, Gunbuk, and Daejang deposits are neighboring vein-type hydrothermal Cu deposits located in the SE part of the Korean Peninsula. These three deposits are formed by magmatic-hydrothermal activity associated with a series of Cretaceous granodioritic intrusions of the Jindong Granitoids, which have created a series of veins and alterations in a hornfelsed shale formation. The copper deposits have common veining and alteration features: 1) a pervasive chlorite-epidote alteration, cut by 2) Cu-Pb-Zn-bearing quartz veins with a tourmaline-biotite alteration, and 3) the latest barren calcite veins. Chalcopyrite, pyrite, and pyrrhotite are common ore minerals in the three deposits. Whereas magnetite is a dominant mineral in the Haman and Gunbuk deposits, no magnetite is present, but sphalerite and galena are abundant in the Daejang deposit. Ore-bearing quartz veins have three types of fluid inclusions: 1) liquid-rich, 2) vapor-rich, and 3) brine inclusions. Hydrothermal temperatures obtained from the brine inclusion assemblages are about 340–600, 250–500, and 320–460°C in the Haman, Gunbuk, and Daejang deposits, respectively. The maximum temperatures (from 460 to 600°C) recorded in the fluid inclusions of the three deposits are higher than those of the Cu ore precipitating temperature of typical porphyry-like deposits (from 300 to 400°C). Raman spectroscopy of vapor inclusions showed the presence of CO2 and CH4 in the three deposits, which indicates relatively reduced hydrothermal conditions as compared with typical porphyry deposits. The Rb/Sr ratios and Cs concentrations of brine inclusions suggest that the Daejang deposit was formed by a later and more fractionated magma than the Haman and Gunbuk deposits, and the Daejang deposit has lower Fe/Mn ratios in brine inclusions than the Haman and Gunbuk deposits, which indicates contrasting redox conditions in hydrothermal fluids possibly caused by an interaction with a hosting shale formation. In brines, concentrations of base metals do not change significantly with temperature, which suggests that significant ore mineralization precipitation is unlikely below current exposure levels, especially at the Haman deposit. Ore and alteration mineral petrography and fluid inclusions suggest that the Haman deposit was formed near the top of the deep intrusion center, whereas the Gunbuk deposit was formed at a shallower intrusion periphery. The Daejang deposit was formed later at a shallow depth by relatively fractionated magma.

Effects of Carbonate Minerals on Shale-Hydraulic Fracturing Fluid Interactions in the Marcellus Shale

Natural gas extracted from tight shale formations, such as the Marcellus Shale, represents a significant and developing front in energy exploration. By fracturing these formations using pressurized fracturing fluid, previously unobtainable hydrocarbon reserves may be tapped. While pursuing this resource, hydraulic fracturing operations leave chemically complex fluids in the shale formation for at least two weeks. This provides a substantial opportunity for the hydraulic fracturing fluid (HFF) to react with the shale formation at reservoir temperature and pressure. In this study, we investigated the effects of the carbonates on shale-HFF reactions with a focus on the Marcellus Shale. We performed autoclave experiments at high temperature and pressure reservoir conditions using a carbonate-rich and a decarbonated or carbonate-free version of the same shale sample. We observed that carbonate minerals buffer the pH of the solution, which in turn prevents clay dissolution. Carbonate and bicarbonate ions also scavenge reactive oxidizing species (ROS), which prevents oxidation of shale organic matter and volatile organic compounds (VOCs). Carbonate-free samples also show higher pyrite dissolution compared to the carbonate-rich sample due to chelation reactions. This study demonstrates how carbonate minerals (keeping all other variables constant) affect shale-HFF reactions that can potentially impact porosity, microfracture integrity, and the release of heavy metals and volatile organic contaminants in the produced water.