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The story of the US shale revolution is well known. Hydraulic fracturing techniques were executed by Mitchell Energy in vertical Barnett Play gas wells in the early 2000's, vertical wells matured into horizontal multi-stage frac wells, and one of the largest land leasing campaigns in history exploded as operators chased high gas prices.
As the natural gas market became saturated, the industry started to strip the natural gas liquids (NGLs) out of the gas stream to take advantage of the ever-rising oil pricing. When gas prices tumbled in 2011, and oil prices climbed north of $100/bbl, the industry looked to the liquid rich/oil plays, such as the Williston Basin, the DJ Basin, and the Permian Basin.
The turning point came in November 2014 when oil prices fell rapidly. As prices bottomed out at $22/bbl in February 2015, the industry saw a large exodus of operators and capital from the gas rich plays around the US to the liquid rich Permian. The Permian proved to be the haven for oil and gas development with its multiple pay zone targets, high EURs, low break-even costs, friendly regulatory environment, and access to markets. The rush for land, once again ensued, with the hope of an oil price rebound and promise of high returns to capital investors.
The rapid ramp up in activity from 2015–2018 did not come without challenges as it put strain on the availability of services and people, access to pipelines and markets, and access to frac sand/water. This drove up costs and resulted in mixed results for many companies. In addition, operators soon saw that with higher-than-expected gas and water production, expenses to manage these by-products sky-rocketed. Water handling and disposal became a huge portion of operating expenses and with gas export facilities at full capacity, companies started to flare gas in large volumes. Associated gas became a waste product, causing operators needed remove the gas and associated liquids from the revenue stream, and in some cases pay a high cost for flaring permits, rather than shutting in wells.
By 2019, a shift in the investment community was well underway. The days of growth-focused investment were coming to an end, and investors wanted to see returns on their investments. As prices still hovered around the $55/bbl range, investors were getting anxious to recover their capital invested in the industry, and throughout 2019 operators all talked about the ability to generate free cash flow. This paper analyses the free cash flow for three key unconventional basins across the US and discusses the associated economic impacts in each basin.
Travers, Patrick (Dolan Integration Group) | Burke, Ben (HighPoint Resources) | Rowe, Aryn (HighPoint Resources) | Hodgetts, Stephen (Dolan Integration Group) | Dolan, Michael (Dolan Integration Group)
Scope: The management, treatment and disposal of hydraulic fracturing flowback fluids and produced water presents a major challenge to operators. Though the volumes of water are tracked closely during operations, the sources of that water are not well understood. The objective of this study is to apply a cost effective and proven technique, stable isotope analysis, along with an extensive sampling program (n>1,500 samples) to describe the contributions of variable water sources through completions, flowback and the production lifecycle of multiple horizontal, hydraulically fractured wells in the Denver Basin, Colorado.
Methods: The water stable isotopes of hydrogen (1H and 2H) and oxygen (16O and 18O) are conservative tracers and particularly advantageous because they occur naturally in these systems and rely on well-established scientific and analytical techniques. Sample collection is simple and does not require specialized equipment or operational downtime. 80 horizontal, hydraulically fractured wells completed in the Cretaceous Niobrara or Codell Formations were selected for this study. More than 1,500 samples were collected and analyzed in total, including: baseline samples of the source water used to stimulate the well, time series samples collected at daily or semi-daily intervals during the early weeks of flowback, and samples collected several months after the wells were brought on production. Samples of produced water were also collected from legacy wells in the field as well as offset wells being monitored for frac hits during completions.
Results: Samples of the near surface and shallow aquifer source water collected prior to hydraulic fracturing fell on or near the global meteoric water line (GMWL) as defined by Craig (1961). This isotopic signature is expected for modern water in aquifers charged by precipitation. In contrast, samples collected during flowback and production were significantly enriched in 2H and 18O. Furthermore, the magnitude of the isotopic difference between the source and flowback water increased with time until equilibrating after several months. This equilibrated composition is consistent for Niobrara and Codell wells in the field, as well as legacy wells sampled and consequently is hypothesized to be indicative of native formation water. The study did find exceptions, particularly with wells known to be connected to major fault or fracture networks. These samples deviated from typical formation water signatures, potentially indicating the migration of deeper sourced fluids or the vertical mixing of shallower fluids with Cretaceous waters.
Significance: The scale of this study is unique in the literature and provides novel and comprehensive insight into the dynamics of flowback and the sources of produced water in the Denver Basin. This study demonstrates that these data can clearly differentiate water injected during stimulation from native formation waters, as well as track the magnitude and duration of well cleanup. It can also identify wells that may be producing water with a unique composition due to fluid migration through faults or fracture networks or due to nearby well communication.
While massive advances in completions and low cost per barrel to produce horizontal wells are the driving forces behind shale production in the US, optimization of target and steering into the best rock is a choice that operators can make to increase well performance, efficient recoveries, and ultimate recoveries from the well. The idea that geology doesn't matter and "you can frac into it" is a limiting thought process and practice. This case study presents work where the best rock was identified and calibrated by geologic, engineering, and completions data and XRD and XRF measurements taken along two laterals. Great lengths were taken to design a subsequent 9-well program to steer in the best rock throughout the well using real time acquired-while-drilling data based on the two well calibration, drilling subsequent 9 wells in better rock and ultimately outperforming type curve. This paper presents a case study in the Denver-Julesbeg (DJ) Basin where two wells drilled in 2017 collected Energy-dispersive X-ray Fluorescence (ED-XRF), Bulk X-ray Diffraction (XRD), HAWK Programmed Pyrolysis, and Mass Spectrometry (MS) analyzing the full hydrocarbon spectrum of C1-C10 and inorganic gasses collected while drilling. These analyses were performed on one Niobrara C twomile lateral, and one Codell two-mile lateral. These data were carefully synthesized to provide a chemostratrigraphic characterization that was integrated with completion data to create a set of best practices for geosteering protocol in a 9-well multi-target drilling program executed in 2018.
Deep formation damage caused by killing fluid frequently occurs in blowout wells and clean-up operations may result in early water breakthrough and less hydrocarbon recovery. This paper presents three innovative practices applied in oil and gas wells that suffered blowout accidents for more hydrocarbon recovery. i.e.:
These methods have been successfully utilized in more than 40 wells for over 50 years. The three typical field examples are illustrated. One of them is an oil well in sandstone reservoir, with double oil rate as the nearby wells. The rest are a gas well in massive carbonate pool with bottom water, with the most prolific gas production in the field, and a gas well in a naturally fractured reservoir, with Gp of over 180 BCF.
Each year tens of thousands of oil and gas wells are successfully drilled worldwide. The overall safety record of the drilling and workover operations is quite satisfactory. On occasion, however, blowout problems can arise during drilling and workover where the control of a well is lost, whenever a well begins to flow uncontrollably.
Tang, Xueqing (RIPED, PetroChina) | Dou, Lirong (RIPED, PetroChina) | Wang, Ruifeng (Petro Energy Co.) | Wang, Jie (RIPED, PetroChina) | Wang, Shengbao (RIPED, PetroChina) | Wang, Jianshun (RIPED, PetroChina) | Shi, Junhui (RIPED, PetroChina)
Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects:
As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.
Discovered in July, 2006, Jake field is situated at the north part of Fula Western trend with oil-bearing area of approximate 45,714 acres. This field contains two distinct productive formations in the Early Cretaceous age: Bentiu oil reservoir at the average depth of 4,724 ft plus Abu Gabra gas-condensate reservoir at the average depth of 8,425 ft. The producing reservoirs are normally pressured, and the field has a normal geothermal gradient of approximately 2.60℉/100 ft.
Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The total number of drilled was 19, including 5 updip wells penetrated oil and gas zones, the remaining 14 downdip wells completed at principal oil zones. A unique co-development project of oil and gas had been performed since the start-up of field in July, 2010, including three phases:
Phase I: Prior to start-up of the field, In-situ gas injection was initiated. Single tubing string completion was utilized in updip wells, packer isolated oil and gas zones so that high-pressure gas could produce from the tubing and oil could produce from the annulus. After commencement, gas from updip wells was injected into downdip wells to maintain reservoir pressure and minimize water influx. The remaining gas was used to gas-lift at updip wells.
Phase II: Following pressure depletion of oil and condensate gas zones, gas-lift wells became inefficient. The packerless tubing string was extended to the bottom of perforations for commingling production of oil and gas condensate zones at updip wells. Well stream was produced from the casing annulus while recycling gas was injectied from compressors into the tubing for gas lift. Nitrogen injection was conducted at downdip wells.
Phase III: After water breakthrough, infill wells between updip and downdip wells were drilled for nitrogen injection to mitigate the water cut rising trend.
Actual production performance of oil and gas co-development is better than sequential production of oil and gas. Initial well production at two producers reached over 10,000 BOPD, Current recovery factor for oil is 25% and gas is 36%. Oil is producing at the level of 18,000 BOPD with average offtake rate of 5.8%. Simulation confirmed that ultimate recovery factor for oil could be over 50%.
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.
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
The Niobrara Shale in the United States has ramped up into a hot play that could soon bring an explosion of horizontal drilling in Colorado and Wyoming. The combination of horizontal drilling and multistage hydraulic fracturing is transforming the Niobrara from a target that has been drilled vertically and primarily for gas for nearly 100 years into a liquids-rich play that is capturing considerable attention. Speaking at the 2011 SPE Annual Technical Conference and Exhibition in Denver, John Ford, general manager of Colorado’s Wattenberg field at Anadarko, described the growing Niobrara activity as “really the next big thing.”
That optimism was understandable. In November, Anadarko announced that its leases at Wattenberg may hold more than a billion barrels of recoverable oil and natural gas. The statement noted company drilling success in 11 recent wells at the field, including the Dolph 27-1HZ horizontal well that showed initial production of more than 1,100 B/D of oil and 2.4 MMcf/D of natural gas. These latest wells have given the company confidence that it can drill between 1,200 and 2,700 wells in northeast Colorado, with approximately 160 wells planned for this year. Based on results so far, the company expects ultimate recovery of between 500 million and 1.5 billion bbl of oil, natural gas liquids, and natural gas on an equivalent basis.
Anadarko is not alone. Chesapeake Energy, Noble, Encana, and EOG Resources are among the largest acreage holders and the most active drillers of many companies—including numerous small independents—probing the Niobrara. Majors such as Shell and Marathon Oil have significant acreage.
There are more than 50 operators in or near the Wattenberg field alone. Situated north/northeast of the Denver area, Wattenberg is the largest producing field in the Denver-Julesburg (D-J) Basin and one of the largest onshore oil and gas fields in the US.
Reservoir Rock and Producing Regions
Although the Niobrara is usually referred to as a shale, its reservoir rock consists primarily of limestone or chalk intervals, said Steve Sonnenberg, professor of petroleum geology at Colorado School of Mines in a recent edition of the AAPG Explorer (published by the American Association of Petroleum Geologists). “The formation demonstrates facies changes that range from limestone and chalk in the eastern end to calcareous shale in the middle and eventually transitioning to sandstone farther west,” said Sonnenberg, a past president of AAPG. “Depth and thickness are highly variable.”
This paper illustrates the natural gas in-situ huff and puff pilot test applied in Jake field in Sudan. B pool of Jake field is a medium GOR (100 scf/bbl) pool with medium well productivity, averaging at 500 BOPD by PCP testing. Operator intended to increase well output to reduce operational and safety hazards. Substantial high pressure natural gas below B pool could be utilized and injected into B pool to boost recovery factor. This process undergoes injection, soaking, production, similar to steam huff and puff. Pilot test of in-situ huff and puff has been planned by following methodology: 1) driving mechanisms investigation of huff and puff and confirm applicability in B pool; 2) gas production from tubing and injection into B pool through casing without using gas compressors; 3) injection and production parameters optimization by nodal analysis;
Pilot test on two wells JS-4 and JS-1 began in Aug. 2010 and flowed naturally after 20 days injection and gained 20 fold well rate increase compared with PCP wells, amounting to 10000-13000 BOPD, setting the highest well rate record in Sudan. Conclusions drawn from pilot tests were as follows:1) in-situ natural gas huff and puff was feasible; 2) gas injection could boost reservoir pressure and reduce in-situ viscosity and enhance recovery factor; 3) gas from tubing into casing was proved simple, efficient and cost-effective 4) production rates could be optimized using nodal analysis. Sudan is abundant in layered pools with lower gas and upper light oil, natural gas in-situ huff and puff has wide applications for similar pools in Sudan. Successful natural gas huff and puff pilot test in this paper highlighted huge oil rate gain, innovative well bore structure, cost-effective operation, paving the way for future full field implementation.