Gao, Jia Jia (Department of Civil & Environmental Engineering, National University of Singapore) | Lau, Hon Chung (Department of Civil & Environmental Engineering, National University of Singapore) | Sun, Jin (Institute of Deep-sea Science and Engineering, Chinese Academy of Sciences)
Conventional drilling design tends to inaccurately predict the mud density needed for borehole stability because it assumes that the porous medium is fully saturated with a single fluid while in actuality it may have two or more fluids.
This paper provides a new semi-analytical poroelastic solution for the case of an inclined borehole subjected to non-hydrostatic stresses in a porous medium saturated with two immiscible fluids, namely, water and gas. The new solution is obtained under plane strain condition. The wellbore loading is decomposed into axisymmetric and deviatoric cases. The time-dependent field variables are obtained by performing the inversion of the Laplace transforms. Based on the expansion of Laplace transform solution, we derive the unsaturated poroelastic asymptotic solutions for early times and for a small radial distance from an inclined wellbore. The model is verified by analytical solutions for the limiting case of a formation saturated with a single fluid. The impact of unsaturated poroelastic effect on pore pressure, stresses and borehole stability is investigated.
Our results show that the excess pore pressure due to the poroelastic effect is generally higher for the saturated case than the unsaturated case due to the large difference between the compressibility of fluid phases. The time-dependency of the poroelastic effect causes the safe mud pressure window of both the unsaturated and saturated cases to narrow with increasing time with the unsaturated case giving a narrower safe mud pressure window. Furthermore, this window narrows with increasing initial gas saturation. The commonly used assumption that the formation is fully saturated by one fluid tends to be conservative in predicting the mud density required for borehole stability.
This new semi-analytical poroelastic solution enables the drilling engineer to more accurately estimate the time-dependent stresses and the pore pressure around a borehole, thus allowing him to design the mud weight to ensure borehole stability.
Located in the Gulf of St. Lawrence in Quebec, Anticosti Island extends over a length of 220 km and a maximum width of 56 km and covers an area of 7,943 sq-km (3000 sq-mi). Anticosti is a large ESE-WNW oriented structure situated along the Laurentia passive margin of Ordovician carbonates that extends from western Texas to Newfoundland (figure 1). The geological units forming the island are of Paleozoic age, ranging from the Cambrian to the end of Silurian. The territory, almost unhabited, has large subsurface areas virtually unknown since very few exploration wells were drilled on the island. However, various data accumulated over sixty years now allow us to evaluate the petroleum potential of the region. The current exploration phase recognized the potential of the Middle Ordovician Macasty Shale as a liquid-rich resource play (potential for light oil/condensate production).
The Macasty Shale has properties which compares favorably with other North American shale resource plays and which may be a positive indicator for potential resources initially-in-place. Technical evaluation indicates that the level of organic richness, the thermal maturity, the mineralogy, the formation pressure and temperature, as well the structural features observed thus far in the Macasty in the Deep Macasty Fairway compares favorably with published findings for the oil-rich Utica/Point Pleasant Shale in Ohio and the Eagle Ford Shale in Texas. Resources assessment studies (P50 - Best Estimate) recently published by different groups corroborate the analytical results and the interpretation of the authors concerning the high hydrocarbon potential of the Anticosti Basin. For the Macasty Shale only, current estimations established the potential oil initially in-place (OIIP) to be over 40 billion barrels.
According to recently released by the Government of Quebec report, the exploitation of hydrocarbons on the island would be likely to meet up to 113% of the current annual consumption of Québec's natural gas and up to 9% of oil consumption. It could represent an annual intake of more than two billion dollars to the Quebec GDP. Considering the lifetime of the project which could extend over 75 years, activities on Anticosti Island could create and maintain on average between 2200 and 2600 direct and indirect jobs annually (Quebec Government, 2016).
Unconventional shale plays have been rapidly developed over the past six years with over 13,000 wells completed in the Eagle Ford alone (Wood Mackenzie 2015). This pace has been characterized by constant changes in development and operations, complicating industry's ability to analyze and compare well and reservoir performance. The resulting challenge faced by the petroleum industry is to identify metrics that relate to long-term well and reservoir performance.
The petroleum industry uses various metrics to analyze and report unconventional well performance. Most of the traditional single well performance metrics (i.e. Initial Production (IP), 30 day cumulative Barrels of Oil Equivalent (BOE), etc.) do not explicitly account for geology, fluid behavior, well operations, or drainage volume. As a result they often do not correlate to long-term well performance and should not be used for development decisions (i.e. best practices on completions, well spacing, production operations, etc.). This paper will discuss strengths and weaknesses of various performance metrics and describe the modification and application of a well-established metric to address some of the limitations described above. The modified metric has been validated using long-term production data from hundreds of Eagle Ford wells. The paper will also show how the metric was applied to support development decisions in BHP Billiton's Black Hawk acreage.
The horizontal shale revolution in the Eagle Ford reservoir began with Petrohawk's first well in Hawkville, STS 1H, in 2008. BHP Billiton's acquisition of Petrohawk's Eagle Ford acreage in 2011 has since resulted in over 900 wells being drilled in its flagship Black Hawk acreage and over 530 wells in Hawkville (Fig. 1). Current producing well count from the two fields is over 1,400 wells. Black Hawk development is mainly focused in De Witt County in partnership with Devon Energy. Fig. 2 shows a typical well from the Black Hawk field and its heterogeneous petrophysical properties. A unique combination of several factors—structural setting, high total organic content, low clay content, and an overpressured reservoir in most of the acreage—make Black Hawk a world-class unconventional field. However, development is complicated by several factors such as depth ranging from 11,000 feet to 13,500 feet, variable thickness (Fig. 3) and fluid properties (Fig. 4), and extensive lateral (Fig. 5) and vertical heterogeneity.
Diakhate, Mamadou (Pioneer Natural Resources) | Gazawi, Ayman (Pioneer Natural Resources) | Barree, Robert David (Barree & Associates) | Cossio, Manuel (Pioneer Natural Resources) | Tinnin, Beau (Pioneer Natural Resources) | McDonald, Beth (Pioneer Natural Resources) | Barzola, Gervasio (Pioneer Natural Resources)
This paper outlines a REFRAC pilot testing program conducted in the Eagle Ford shale.
As wells in the Eagle Ford accumulate production over time and the pressure around the horizontal wellbore declines, it is important to protect the wells and associated reserves from any offset fracture stimulation and communication that could potentially cause damage. Re-fracturing trials in older fields such as the Barnett have yielded a positive enhancement of the well performance. This paper gives an evaluation in the eagle ford of the effectiveness of the refrac on protection of the older wells.
Actual refracturing pumping data from this field is used to demonstrate the type and mechanism of fracture reorientation
Re-fracturing an old horizontal well with 5000 ft. lateral length and more than 800 existing perforation holes in the casing is very challenging and does require a careful integration of reservoir knowledge, completions skills and experience. The technical team of Pioneer Natural Resources has developed an integrated workflow to design and execute a re-fracturing job for an Eagle Ford well. The work flow include: 1) Reservoir study to identify the lower pressure areas along the lateral. This is done by integrating all the surveillance data from the well such as micro-seismic, tracer logs, production data. 2) Identify wells within the drilling schedule that are offsetting older unit primary wells with high cumulative production. 3) Design of a single fracturing job with several sub-stages separated by diverting agents. Volumes and pump schedules will be specific for each candidate based on proximity to offset well, lateral length, and existence of geological structures. The candidate wells in the pilot program will be re-fractured and the re-fracturing field execution procedure will be adjusted based on lessons learned from this pilot experimentation. The results from these pilot wells when looking at the fracture gradient changes before and after refrac, the radio-active tracers and well performance will be evaluated following field execution.
Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.
The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures . The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1st commercial shale gas discovery possible in shale gas history.
In 2008, the operator drilled several successful wells in the Hawkville field of what would become the Eagle Ford shale play. Early results led to substantial land acquisition. The Eagle Ford, while continuous over wide sections, varies substantially in terms of fluid and rock properties. Figure 1 shows a cross section for an arbitrary line through Black Hawk and Hawkville to the Maverick basin, showing the relative changes in thickness and Young’s modulus.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168973, "Unconventional-Asset-Development Work Flow in the Eagle Ford Shale," by David Cook, Kirsty Downing, Sebastian Bayer, Hunter Watkins, Vanon Sun Chee Fore, Marcus Stansberry, Saurabh Saksena, and Doug Peck, BHP Billiton Petroleum, prepared for the 2014 SPE Unconventional Resources Conference - USA, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed.
Development of the Eagle Ford shale typically consists of horizontal wells stimulated with multiple hydraulic-fracture stages. This paper presents a pragmatic integrated work flow used to optimize development and guide critical development decisions in the Black Hawk field. Geoscientists and reservoir and completion engineers worked collaboratively to identify optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells.
In 2008, the operator drilled several successful wells in the Hawkville field of what would become the Eagle Ford shale play. Early results led to substantial land acquisition. The Eagle Ford, while continuous over wide sections, varies substantially in terms of fluid and rock properties. Fig. 1 shows a cross section for an arbitrary line through Black Hawk and Hawkville to the Maverick basin, showing the relative changes in thickness and Young’s modulus.
An understanding of the characterization of shale systems for simulation has evolved rapidly. Flow contributions from natural fractures, induced fractures, and matrix rock along with the nature of the hydrocarbon deposit itself should be considered. Perhaps even more important is regional variation. In the world of conventional assets, property estimation needs to be reliable only for a small geographical area, often within one sandstone structure of a few square miles at most. This can be compared with the scale of the play in Fig. 1. For conventional reservoirs, standardized laboratory methods and years of research and trial and error have educated our approaches to well-defined best practices. In shale plays, these have not yet been fully worked through and adopted by consensus, often leaving the owner of the asset as the arbiter of methodology.
In this paper, the use of microseismic data for calibration and modification of wellbore temperature models will be introduced. Moreover, fracturing fluid distribution obtained using the modified temperature numerical model is coupled with the microseismic field data for several Eagle Ford shale wells to improve hydraulic fracture stimulation characterization. By measuring the temperature change along the wellbore, distributed temperature sensing (DTS) data may provide relative fluid distribution. This information may be used to assess the simple geometry of the hydraulic fractures, the fracture initiation points along the wellbore, wellbore integrity issues, and the effectiveness of isolation tools. With recently published wellbore temperature models, quantitative information about which zones receive the stimulation fluid can be numerically solved. However, DTS measurements and fluid distributions calculated using DTS data are restricted to the wellbore and near wellbore environment. For far field diagnostics of hydraulic fracturing stimulation other measurements are needed, specifically microseismic. By combining these two measurements, a new workflow is created which incorporates both the far field and wellbore measurements to characterize hydraulic fractures, both real-time and after the stimulation job. This workflow is especially useful in reservoirs that are naturally fractured or in wellbores were stress shadowing effects are significant, such as multistage fracturing multiple wells that are in close proximity to each other. In these scenarios the path that the fluid travels may be complex, even in the near wellbore environment. Due to this complexity, fluid distributed calculations based on DTS data may provide misleading results. Using information gained from microseismic, the wellbore temperature models may be modified to increase the reliability of the numerically calculated fluid distributions. The purpose of this paper is to propose how microseismic data may be used to modify the wellbore temperature models, and how stimulation fluid placement determined from the modified models may then be coupled with the microseismic to improve hydraulic fracture stimulation characterization.
This success has been driven by a flexible land leasing system for drilling rights, a mature infrastructure network for oil and gas transportation, a favorable fiscal regime, a well-established and very active service industry, and easy access to capital and world leading technologies. To what extent are these attributes singular to North America, and to what extent can the extensive development of unconventional resources seen in North America be replicated in other parts of the world? Many countries have well established and successful conventional E&P activities and fiscal/contractual terms, but have struggled with the question as to how applicable these terms are to unconventional resource exploration, evaluation and development. This paper will seek to identify the key differences in the application of North America's leasing, regulatory and fiscal regime to shale development, as compared to alternative systems applied elsewhere in the world. The authors start by examining the fundamental cost and production profiles of conventional and unconventional wells in two North American onshore plays, and then in two potentially competing North American capital investment opportunities in order to establish whether there is anything fundamental in the economics of unconventional exploitation that requires different treatment. This analysis is then used to consider economics under cost, regulatory and fiscal regimes outside of North America.
Cook, David (BHP Billiton ) | Downing, Kirsty (BHP Billiton ) | Bayer, Sebastian (BHP Billiton ) | Watkins, Hunter (BHP Billiton) | Sun Chee Fore, Vanon (BHP Billiton) | Stansberry, Marcus (BHP Billiton ) | Saksena, Saurabh (BHP Billiton ) | Peck, Doug (BHP Billiton )
The Eagle Ford Shale is recognized as the largest oil and gas development in the world, based on capital investment (Woodmac report, Jan 2013). Development typically consists of horizontal wells stimulated with multiple hydraulic fracture stages. Almost $30 billion will be spent developing the play in 2013, and optimizing the completion design and spacing of these wells can result in large rewards for the companies involved.
This paper presents a pragmatic integrated workflow, used to optimize development and guide critical development decisions in the Black Hawk field, Eagle Ford Shale. Geoscientists, reservoir and, completion engineers worked collaboratively to identify the optimal completion designs and well spacing’s for development focus areas.
Multiple simplistic simulation models were history matched to existing production wells. Wide uncertainty exists in many key reservoir and completion parameters. Using stochastic realizations from ranges of key properties, uncertainty was reduced using the history matching process. The resulting calibrated reservoir scenarios formed the basis of optimization studies for development drilling and down spacing.
Completion design parameters, including fracture stage length, perforation clusters per stage and landing point for the lateral, were evaluated in hydraulic fracture models. The resulting fracture geometries were simulated and the optimum completion design and well spacing determined for each area. The optimal development was shown to vary by region, due to changing reservoir, fluid and geomechanical properties.
The use of multiple subsurface realizations, spanning an appropriate range of uncertainty, was critical to the success of this study. Economic analysis across a range of potential outcomes enabled robust development decisions to be made. As a result of this work, field trials to test proposed changes to the completion have been initiated, and development drilling plans updated to reflect the optimal well spacing for each lease.