Texas regulators rejected a rare challenge to gas flaring in the state after an oil company argued that a flaring ban would force it to shut in wells, damaging the reservoir and reducing future oil production. There is every reason to believe that enhanced oil recovery through huff-and-puff injections in US tight-oil plays could be a technical success across large numbers of wells. However, widespread economic success remains uncertain. This paper demonstrates how engineers can take advantage of their most-detailed completions and geomechanical data by identifying trends arising from past detailed treatment analyses. This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells.
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.
Chevron has performed surveillance, analysis and optimization (SA&O) pilot study in its Midland Basin Wolfcamp tight oil development area. In this paper, we will focus on the pilot overview, production logs, rate transient analysis (RTA), and multiple well interference pressure transient analysis (PTA).
The pilot area consists of a center 20-acre vertical well and four pressure monitoring wells in four directions with a distance of 460
RTA has been performed in the center well based on the production rate measured from a dedicated test separator, flowing bottomhole pressure from a downhole memory gauge, and zonal contributions from production logging (PLs). PLs show that fluid comes primarily from the Spraberry, secondly from the Lower Wolfcamp, and some from the Strawn and Atoka. The RTA shows that effective drainage area of the well is less than 20 acres. In addition, fracture half-length and effective permeability are degrading with time, which impacts the well's EUR. The acquired pressure responses in observation wells have been studied with non-linear numerical model in PTA to better characterize the fracture network and reservoir. It shows a high possibility of connecting with neighbor wells in certain formations and exhibiting characteristics of time-dependent fracture closing. Production performances with original 40-acre spacing wells and recently drilled 20-acre infilled wells are compared, indicating that 20-acre wells helps to improve oil recovery and economics. The center well was shut in for more than 9 months to get buildup data. During the 5 month post shutin production (PSP), the well had significantly higher oil rate and positive net oil recovery with decreased GOR and water-cut.
The pilot sheds light on first principles and tight oil development strategy. Accurate microseismic data, production logs, interference well testing, and rate transient analysis are powerful tools for unconventional studies.
Running a shale exploration and production operation requires a sharp focus on costs, but not all are measured the same. BHP Billiton’s method for evaluating the cost of drilling an unconventional well is different from the one used to gauge the cost of completing one. The difference reflects the potential production upside of spending more to fracture formations more effectively compared with drilling. BHP is seeking ways to create more productive fracture networks by manipulating the stresses in the rock between wells, and seeking efficient ways to go back into older wells without the cost of the hardware needed for the initial fracturing work. He said the Australian mining and energy company realized about a year after acquiring onshore assets in the US that the management methods used for offshore development were not going to work when mass producing wells onshore.
"High-Pressure/High-Temperature BOP Equipment Becoming a Reality"
The offshore industry has taken another step toward opening up new deepwater frontiers to exploration with Maersk Drilling ordering the first 20,000-psi blowout preventer (BOP) made by GE Oil and Gas. The BOP is expected to be delivered in the first half of 2018 and is part of a multiyear collaboration between Maersk and BP to design a new generation of offshore drilling rigs for deepwater basins dubbed “20K Rigs.”
The ultimate goal is to enable the development of highpressure/ high-temperature reservoirs with pressures up to 20,000 psi and temperatures as high as 350°F. The technical limit of the highest-rated BOPs in operation today is 15,000 psi and 250°F. BP believes that with the 20,000-psi BOPs, and other technologies in development, it will be able to develop fields that may add an additional 10 billion to 20 billion BOE across its portfolio.
"Refracturing Success Demands a Better Understanding of Past Failures"
Refracturing older unconventional wells is likely to reward those willing to investigate the reasons why production declines and what can be done to restore it, according to George King, distinguished engineering adviser at Apache Corp.
King talked about what has been learned from refracturing wells, and why companies need to invest in answering the questions that remain unanswered in this young branch of the exploration and production (E&P) business. “We are going to have to look for better ways of fracturing initially and refracturing these wells,” he said during a webcast, which can be found under online events at SPE.org.
"US Approves BP's use of Unmanned Aerial Vehicles in Alaska"
In June, the United States Federal Aviation Administration (FAA) issued the first approval for the overland use of unmanned aerial vehicles (UAVs) in Alaska. The authorization was granted to BP and UAV maker AeroVironment for aerial surveys of roads and pipelines in Alaska’s prolific North Slope oil fields. Last year, the FAA issued a more restrictive approval to BP and ConocoPhillips that allowed the companies to fly UAVs over Arctic waters, and only during optimal conditions.
BP and AeroVironment carried out the first approved flight on 8 June, using a Puma AE, a hand-launched vehicle that is 4.5 ft long with a 9 ft wingspan. BP intends to use the lightweight UAV for “high-accuracy” land surveys and for map making to identify maintenance requirements on roads and infrastructure. “The (unmanned aerial system) technology has potential to improve safety, efficiency, and the reliability of BP’s Alaska North Slope infrastructure and maintenance programs,” said Dawn Patience, a BP spokesperson.
"BHP Billiton Testing New Methods To Maximize Returns on Completions"
Running a shale exploration and production operation requires a sharp focus on costs, but not all are measured the same. BHP Billiton’s method for evaluating the cost of drilling an unconventional well is different from the one used to gauge the cost of completing one.
The difference reflects the potential production upside of spending more to fracture formations more effectively compared with drilling. BHP is seeking ways to create more productive fracture networks by manipulating the stresses in the rock between wells, and seeking efficient ways to go back into older wells without the cost of the hardware needed for the initial fracturing work.
"Saudi Aramco Wants Fields Fully Smart by 2017"
Saudi Aramco’s new strategy aims to implement its intelligent field (I-Field) concept in all its upstream operations by 2016-2017, according to a source close to the company.
The move is part of the company’s efforts to be more proactive in field management and move toward a vision of autonomous fields. “All of Saudi Aramco’s fields are set to be intelligent by 2016- 2017,” the source said.
Saudi Aramco is considered one of the leading national oil companies to adopt a smart field initiative through the I-Field concept, which integrates real-time data in its upstream business processes. It currently has 19 I-Fields underway.
"Saudi Aramco Aims to Slash Costs"
Saudi Aramco is working on slashing the production cost of tight formations to around USD 2 to USD 3 per thousand cubic feet in the next couple of years, according Adnan Kanaan, manager of the Gas Reservoir Management Department (GRMD) at Saudi Aramco.
Kanaan said that his company expects to reach its target that may lead to a break-even cost that would equal the best unconventional plays in the US. “We are seeing good signs from the sandstones and good costs in our drilling and completions,” Kanaan said during the 21st World Petroleum Congress held recently in Moscow.
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.
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.
In conventional reservoirs, the correlation of reservoir quality (RQ) to production is a standard practice. RQ is defined as the product of various rock properties, including saturation (S), porosity (???), thickness (h) and, in some cases, permeability (k). Plotting RQ against normalized well production gives an indication of rock type and hence production trends.
To use this methodology in unconventional reservoirs, it is necessary to modify the relationship to account for the complexity and heterogeneous nature of shale rock. Modification of the method involves the identification of the most representative combination of rock properties used to calculate reservoir quality, which are then compared to multivariable, normalized cumulative production at different time intervals. Applying this relation in the Eagle Ford shale resulted in the observation of two trends, implying that different production trends were in play and should be further investigated.
This paper presents a detailed well-by-well study conducted in the Eagle Ford shale to define the rock characteristics that caused the presence of two production trends. History matches using numerical modeling and rate transient analysis were performed to verify whether two production trends were present. When available, borehole images can be used to validate and extrapolate this localized production analysis to a basin-level understanding.
The objective of this study was to determine a correlation between RQ parameters as obtained from well logs and production performance in the Eagle Ford shale. This led to the identification of different rock types, implying different production trends. This correlation technique has been used in the past for carbonates, sandstones (Pickett and Artus, 1970) and muddy sands (Aguilera, 1995) and is known as "petrophysics-to-production?? methodology. The original methodology correlates recoverable production from decline curves with an RQ index (a function of So, ???h and k) as depicted in the left plot in Figure 1a, which shows three different production trends. Pickett (1970) identified that each trend corresponds to a different rock type with a different production performance where the gentler trend is due to a non-fractured rock type (k/???)2. For this study, the original approach has been adapted as depicted in the right plot in Figure 1b by modifying the production term as cumulative production normalized to lateral length and the RQ index defined using a petrophysical model.