Hydraulic fracturing is a typical and vital technique applied in shale gas reservoir development. Numerical simulation used to be a common tool to optimize the parameters in hydraulic fracturing design determining the stage numbers, injection pressure, proppant amount, etc. However, the current understanding of shale gas storage and transport mechanism (e.g. adsorption/desorption, diffusion) is basically adopted from the lessons learned from coal seams through past experience, which might not help an efficient numerical simulation development.
In this study, how artificial intelligence assisted data driven models assist the hydraulic fracturing design in shale gas reservoir is discussed. It starts by collecting field data and generate a spatial-temporal database including reservoir characteristics, operational/production information, completion/stimulation data and other variables, Neural Network models are then developed to study the impacts of all parameters on gas production as well as perform history matching of the field history. The AI assisted model with acceptable matching of field data can be used to model different hydraulic fracturing design scenarios and provide predictions on well production.
Use of diverters for altering fluid distribution among created hydraulic fractures in horizontal wells has gained popularity in recent years, both for initial and re-fracturing treatments. Aims in initial fracturing treatments have included creating more uniform distribution of slurry within the created fractures, increasing stage efficiency by reducing the number of pumping stages while increasing the number of clusters per stage, increasing the number of fractures created in openhole completions, reducing interactions between fractures in adjacent horizontal wells, etc. In re-fracturing treatments, a popular application is for altering fluid distribution in wells re-treated without isolation between stages (Pump & Pray/Bullheading) with the intent of increasing the number of re-activated fractures and initiating new fractures through added perforations.
Engineering analysis of the mechanics of fluid diversion has not received the same degree of attention as its use. The reported discussions are often limited in their scope, two-dimensional in structure, and somewhat speculative in their conclusions.
This paper divides the targets of diversion into three categories; at the wellbore/perfs, near wellbore, and deeper inside the fracture. It divides the types of diverters into three categories, mechanical, solid particulate (including proppants), and chemical. The applications are divided into two categories, initial and re-fracturing, together with highlighting their differences and requirements for successful diversion. The paper discusses how presence of proppant changes the fluid distribution in favor of more conductive perforations. It considers the fracture as a three-dimensional structure, extending on both sides of the wellbore. It describes how different diverting agents cause fluid redistribution between the fractures, and the important role of proppant in some applications. It shows that as the target of fluid diversion moves away from the wellbore the chances of its success become smaller and more unpredictable, while also the time before effective diversion takes place becomes longer.
Comprehensive understanding of the mechanics of fluid diversion helps in the selection of the type of diverter and how best to deploy it for achieving specific objectives and results.
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.
Another reminder that it costs more to coax the same amount of oil from new wells as for older wells nearby, with a closer look at the big plays and how the wells are completed. PDC’s president and CEO describes the company’s management strategy for its hydraulic fracturing operations in the Wattenberg Field and the Delaware Basin.
The Powder River Basin has emerged over the past year as the latest source of oil production growth for the Lower 48. Companies ranging from a reborn Samson Resources to US onshore mainstays Devon, Chesapeake, and EOG are now betting on the basin to become a long-term core asset. Colorado’s industry lacks the size, variety, and Wild West characteristics of Texas, but that is precisely why the Centennial State’s oil production is surging to record levels. This paper describes a comprehensive field study of eight horizontal wells deployed in the stacked Niobrara and Codell reservoirs in the Wattenberg Field (Denver-Julesburg Basin).
The strategy supports the Maximise Economic Recovery from UK Oil & Gas Strategy and Vision 2035, whose goal is to achieve £140 billion additional gross revenue from UKCS production by that time. The Caribbean nation hopes the auction will lead to at least two exploration projects in a region that has become increasingly attractive thanks to new discoveries and investments made in neighboring countries. Operator Talos Energy now believes Zama’s gross recoverable resource lies in the upper half of its pre-appraisal estimate of 400–800 million BOE. The consortium is working toward a 2020 final investment decision on the project. The explorer has so far encountered 400 ft of reservoir pay zone in an area where it has three other producing fields.
Leaders from two large US onshore rig contractors said their expectations that the rig-count slide would hit a second-quarter bottom were off and are now refraining from making new predictions as to when it will end. Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. Regulators say the blowout that killed five workers on a Patterson-UTI rig in Oklahoma was the product of a slow-moving series of missed signals, misleading testing, and miscalculations that failed to control a natural gas influx. The biggest drilling company appears interested in becoming the most innovative. It is testing inventions ranging from a blowout preventer that is not hydraulically powered to power systems designed like a hybrid car.
The shale sector is making moves to consolidate amid investor pressure to increase cash flow. This deal will form the second-largest producer in Colorado’s DJ Basin. PDC’s president and CEO describes the company’s management strategy for its hydraulic fracturing operations in the Wattenberg Field and the Delaware Basin. Baker Hughes is developing a drill bit capable of auto-adjusting its depth-of-cut feature to handle dynamic drilling conditions. Drilling the Severnaya Truba field in Aktobe, Kazakhstan, has been costly and time consuming.
The large independent put together a team of data scientists, software developers, and petrotechnical staff to create a forward-looking vision for how to use digital technology to solve problems. Baker Hughes is still a GE company, but it has partnered with a second company for artificial intelligence expertise, C3.ai. The deal is expected to speed the integration of AI into oilfield operations by the company which also markets GE’s device analytics platform, Predix. Marathon Oil says its shale fields are producing more oil and gas with less hands-on work from company personnel thanks to a growing arsenal of digital technologies and workflows. Malaysia’s Petronas, Shell Malaysia, and Thailand’s PTTEP are now in the midst of full-scale digital adoption.