Production data and analytical models derived from coupling the linear flow in the reservoir and the linear flow in hydraulic fractures were used in this study to optimize fracture spacing for maximizing productivity of shale oil and gas wells through refracturing. This study concludes that productivity of multi-fractured horizontal wells is inversely proportional to the fracture spacing. The shortest possible fracture spacing should be used to maximize well productivity through refracturing. This supports the practice of massive volume fracturing where as many as perforation clusters with the shortest possible spacing are used for pumping massive proppant into the created hydraulic fractures. Production data analysis indicates that the multi-fractured horizontal oil and gas wells could have higher productivity if they were fractured with less perforation cluster spacing. Mathematical model analysis implies that reducing the cluster spacing from 70 f t t o 15 f t t h r o u g h r e f r a c t u r i n g c a n d o u b l e d w e l l p r o d u c t i v i t y, w i t h t h e M i n i m u m Re q u i r e d C l u s t e r S p a c i n g (MRCS) determined by well completion constraints (packers, perforation clusters, and casing couplings). Result can be checked for fracture trend interference on the basis of analyses of pressure transient data or production data.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the decline in production rate is more than two thirds in the first two years. We are trying to develop chemicals that can be injected into old wells to stimulate oil production before putting the well back in production. The goal of this work is to evaluate chemical blends for such a process at the laboratory scale. The chemical blend contains surfactants, a weak acid, a potential determining ion, and a solvent. Six different solvents were screened: Cyclohexane, D-Limonene, Dodecane, Kerosene, Turpentine, and Green Solvent®. Most of the chemical blends with the solvents extracted about 60% of the oil from shale chips, but the Green Solvent® extracted about 84%. Spontaneous imbibition tests were performed with outcrop Mancos shale cores. Oil was injected into these outcrop cores at a high pressure. NMR T2 distributions were measured for the cores in the original dry state, after oil injection and after imbibition. The aqueous phase from the chemical blend imbibed into the cores and pushed out a part of the oil and gas present in the cores. The surfactant in these blends can change wettability and interfacial tension. The solvent can mix with the oil and solubilize organic solid residues such as asphaltenes. The weak acid can dissolve a part of the carbonate minerals and improve permeability. The synergy can make these chemical blends strong candidates to stimulate oil recovery in shale formations.
Descriptive Analytics is the first step of a three-step data-driven analytics workflow used for managing and optimizing completion, production and recovery of shale wells. The comprehensive data-driven analytics workflow for the unconventional resources is called Shale Analytics (
Shale Descriptive Analytics takes into account seven categories of field measurements;
Two conclusions have been achieved as the result of this study.
Williams, Ryan (Schlumberger) | Artola, Pedro (Schlumberger) | Salinas, Javier (Schlumberger) | Mirakyan, Andrey (Schlumberger) | MacKay, Bruce (Schlumberger) | Hoefer, Ann (Schlumberger) | Kraemer, Chad (Wisconsin Proppants) | Reese, Harrison (PRI Operating) | Roybal, Zack (PRI Operating) | Williamson, Brant (PRI Operating)
Use of regional sand in the Permian Basin dramatically increased in 2018. Regional or in-basin sand is often perceived as lower quality compared to northern white sand (NWS); however, its use is fairly new, and production data has not been available to determine if, or in what cases, higher quality matters. This paper presents the results from a production comparison of Permian Basin wells that were hydraulically fractured with NWS and regional sand or both.
A dataset consisting of approximately 450 wells completed with NWS or regional sand or both within the Delaware and Midland Basins was studied to determine the relationship between production performance and sand type (or quality). To evaluate the effect of sand quality in well production, the dataset was divided in smaller groups of wells with similar reservoir characteristics and completion practices. The initial phase of the study was completed using public domain production data, while the second phase focused on the development of regional reservoir models to forecast production of wells using NWS or regional sand or both.
When analyzing an area containing sufficient wells for a reliable comparison, the survey revealed no statistically significant difference in production for wells that used NWS versus regionally sourced sand. Models were built to predict differences in the production performance of each sand type. These models take into account and demonstrate the effects of differences in sand properties, as well as the impact of the favorable economics associated with regional sands. It was confirmed with the study that the sand type is not a critical factor in regards to production performance when completing wells that are hydraulically fractured in ultralow-permeability nonconductivity-limited reservoirs.
This paper presents an early look at the production numbers of West Texas wells completed with regionally sourced sand in the Permian Basin. The results of the study will encourage operators to further contemplate the use of regional sand when completing wells in ultralow-permeability shale reservoirs. This dataset will continue to evolve and reveal the effects of regional sand over the life of the well; this will be presented in a future paper.
During the last few years, the petroleum industry has been experiencing significant changes in various areas including, workforce, targets of exploration, application of (new) technologies, and general operational areas of focus. A prolonged depression of oil prices, changes in geopolitical atmosphere, the rise of investment in unconventional resources, as well as the implementation of emerging technologies (including digital) have been the primary catalysts of change within the industry. In terms of workforce, these changes have produced leaner organizations, along with the unintended consequence of losing some critical expertise and creating knowledge-gaps at many organizations. The changes, particularly in technology, necessitate a look at the need for the acquisition of new skills, for current and future petroleum engineers, that match new areas of interest – such as data analytics and artificial intelligence.
As the oil industry continues to evolve, it is imperative for academic organizations to consider these changing dynamics and be responsive. This paper outlines the results of a recent survey that targeted industry managers or supervisors who have direct experience with newly minted petroleum engineering graduates (less than five years of experience). The survey asked the participants their opinions regarding the preparedness of recent graduates as they enter the workforce. The survey's intent was to identify the potential need to modify the skills and knowledge currently acquired in academic institutions during the undergraduate study.
A comprehensive survey that posed questions regarding classical and contemplated new petroleum engineering curriculum was sent to recipients, primarily within the reserves and reservoir-engineering sector. The recipients were industry professionals working in operating, service, financial, and consulting sectors of the petroleum industry. More than 200 responses were received. The tabulated results are presented in the paper, along with interpretation of the results. The raw data will be made available through OnePetro as an accompaniment to the published paper.
The paper presents the survey conclusions, proposed action items, and discusses plans for a follow-up survey.
We present an assessment of the impact of low-salinity brine osmosis on oil recovery in liquid-rich shale reservoirs. The paper includes: (1) membrane behavior of shales when contacted by low-salinity brine, (2) numerical model of osmosis mass transport for low-salinity brine, and (3) enhanced oil recovery (EOR) potential of low-salinity osmosis in liquid-rich shale reservoirs. Capillary osmosis causes low-salinity brine to be imbibed into the shale matrix; thus, forcing expulsion of oil from the rock matrix. This oil recovery process is described by a multi-component mass transport mathematical model consisting of advective and molecular transport of water molecules and dissolved ions. In the transport model, the activity-corrected diffusion of the brine solution is used to calculate the volume of brine imbibed into a shale core sample and the resulting expelled oil. We used the mathematical model to match oil recovery from two carefully designed brine-imbibition experiments conducted at Colorado School of Mines. We have concluded that, in oil-wet shale reservoirs, low-salinity brine invasion of the rock matrix is by osmosis rather than capillary force. Thus, osmosis is the only imbibing force that drives the low salinity brine into the reservoir rock matrix. Furthermore, we believe brine osmosis can potentially enhance oil recovery by expelling oil out of the rock matrix and into the micro-and macro-fractures existing in the stimulated reservoir volume.
The US Department of Energy (DOE) has announced the selection of six projects to receive approximately $30 million in federal funding for cost-shared research and development in unconventional oil and natural gas recovery. The projects, selected under the Office of Fossil Energy's Advanced Technology Solutions for Unconventional Oil and Gas Development funding opportunity, will address critical gaps in the understanding of reservoir behavior and optimal well-completion strategies, next-generation subsurface diagnostic technologies, and advanced offshore technologies. As part of the funding opportunity announcement and at the direction of Congress, DOE solicited field projects in emerging unconventional plays with less than 50,000 B/D of current production, such as the Tuscaloosa Marine Shale and the Huron Shale. The newly selected projects will help master oil and gas development in these types of rising shales. This cement will prevent offshore spills and leakages at extreme high-temperature, high-pressure, and corrosive conditions.
Emerson will increase its foothold in the oil and gas industry with the purchase of software maker Paradigm. As the GE-Baker Hughes deal moves closer to finalization we now know who will be leading the combined company. The offshore drilling sector has taken a step towards consolidating an oversupplied market and Ensco will emerge from this most recent deal as the owner of the largest combined fleet of floaters and jackups. A Houston-based energy consultancy concludes that a series of downturn deals have contributed more to the resiliency of the US shale sector than a rise in oil prices.
Upward momentum in US industry operations continues to gather, as the survey conducted by the Federal Reserve for the just-completed fourth quarter of 2017 indicates. Drilling activity in US shale plays is slowing as operators encounter higher prices for labor, equipment, and services, and lower prices for the oil and gas produced.
Digital technologies serve as a primary theme of this year’s group, with a few environmentally conscious firms included in the mix. The well will immediately be brought on production and is expected to flow at more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said. The main goal of production logging is to evaluate the well or reservoir performance. The shale sector is studying the results of a 23-well experiment in the southeastern corner of New Mexico to learn what the wider implications might be. The shale sector is making moves to consolidate amid investor pressure to increase cash flow.