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Summary The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator's portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models. First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.
Abivin, Patrice (Schlumberger) | Vidma, Konstantin (Schlumberger) | Xu, Tao (Schlumberger) | Boumessouer, Wissam (Schlumberger) | Bailhy, Jason (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Sharma, Amit (Schlumberger) | Menasria, Samir (Schlumberger) | Makarychev-Mikhailov, Sergey (Schlumberger)
Infill drilling consists of adding horizontal wells between existing wells to optimize drainage in high-value acreage. New wells are sometimes drilled as close as 250 ft to producing or depleted wells. Fracturing the new wells creates a high risk of fracture-driven interactions (FDI). This paper describes a methodology to characterize well interference on production in unconventional basins and the impact of mitigation technologies.
Data mining, correlations, and statistical tools were developed to extract and analyze a large commercial production database covering major plays in the US. First, cloud-based algorithms were developed to identify and characterize infill wells based on coordinates, well deviations, production dates, and an adjustable radius of interference. Second, monitoring algorithms automatically captured and analyzed abrupt changes in normalized production of infill wells and neighboring wells at the time of infill well stimulation. Finally, the effect on production of both parent and child is immediately displayed on a user-friendly user interface for further visualization and interpretation.
The method was successfully applied to areas experiencing high infill drilling in major basins such as the Williston basin. Results show that production data correlate with historical changes in infill drilling density and fracturing job volumes (proppant and fluid). The production of child wells is then compared to that of their closest parent, which shows some decline as a function of the distance between wells. The systematic workflow also identifies if the basin is prone to positive fracture hits or if there is a significant decrease in the production of existing (parent) wells. The use and impact of diversion technologies as a well interference mitigation method is also studied.
These results give important insights into the effect of field development strategies on well interference and enable recommendations related to well spacing, fracturing designs, and use of fracture geometry control technologies to optimize future well and field development. Production data analysis clearly shows a beneficial impact of both near-wellbore and far-field diversion technologies on production.
Abstract The oil and gas production landscape in North America has seen a paradigm shift since the collapse in oil prices in 2014. Although prices remain challenging, several operators have managed to sustain the relatively long period of low margins through some aggressive approaches. This paper inspects changes in operating strategies and field development plans across all oil-rich basins in the US Rocky Mountain fields and how operators have used a combination of low oilfield service prices, high-graded well locations, and incremental fluid/proppant volumes to increase production. The paper investigates the transformation in operating philosophies since 2014 in four oil-rich basins in the Rocky Mountain region—Williston, Denver-Julesburg (DJ), Uinta, and Powder River. The Bakken formation in the Williston basin represents one of the best-quality rocks in all of North America. However, high oil-price differentials and well costs have made it difficult for drilling to remain profitable. The core of the DJ basin (Wattenberg) has one of the lowest break-even prices in the region, and rig count continues to increase as operators start seeing signs of recovery in the market. The Uinta basin, although relatively small in size, has shown tremendous return potential in the form of multiple stacked pays and promising production results. The Powder River basin poses one of the toughest operational environments in the region owing to wildlife stipulations, harsh weather, and deeper targets. High-graded well locations in the Bakken are limited to few fields, which limits the scope of expansion in the current oil price environment. The DJ basin is challenged with high-density well spacing; estimated ultimate recovery (EUR) per drilling spacing unit (DSU) continues to increase, but EUR per well has gone down by as much as 60%. In the Uinta basin, formations never known to be continuous in the Green River group have shown significant return potential. The Powder River basin has recently attracted large investments from major independent operators as they tackle drilling challenges associated with abrasive rocks and testing optimum lateral landing points. Case studies show how operating strategies have changed with changes in oil prices. The Bakken and DJ basins are relatively mature, and as drilled-but-uncompleted (DUC) inventory continues to increase, depletion from existing wells and interference between fractures is impacting production from new wells. The Powder River basin is still in the exploratory phase, and operators are still working on reducing well-costs, optimizing fracturing-fluid/proppant volumes, and examining productivity of other target rocks. The Uinta basin is in the early phases of expansion, with many of the fields still being explored for scalability. Changes in production maps and completion trends provide a comprehensive understanding of how these variables have impacted oil output from the region since 2012.
Srinivasan, Karthik (Schlumberger) | Krishnamurthy, Jayanth (Schlumberger) | Williams, Ryan (Schlumberger) | Dharwadkar, Pavan (Schlumberger) | Izykowski, Tyler (Schlumberger) | Moore, William Ray (Schlumberger)
Abstract Since the inception of the oil boom in North Dakota, the Williston basin has witnessed a tremendous growth in horizontal drilling and completion activity primarily targeting the Bakken and Three Forks formations. Although the activity in the basin is maturing in terms of our understanding rock quality and completion quality, there is a wide variation of these indices within the basin from one field to another. Some of these variations are clearly noticeable in parameters such as thicknesses of the shale barriers, pore pressure gradients, reservoir permeabilities, porosities and stress gradients. The combined impact of these parameters has a huge impact on key decisions including, but not limited to, completion methodologies, types of proppants and fluids used for completion, number of fracturing stages in the lateral, number of perforation clusters per stage, and well spacing. This paper discusses the evolution of stimulation strategies and completion practices in the Williston basin since 2009. Operators have experimented with cemented and uncemented laterals; sliding sleeves and plug-and-perf completions; lateral lengths ranging from 5,000 to 10,000 ft; perforation clusters ranging from one to six per stage; crosslinked, hybrid, and slickwater fluid systems; proppants ranging from sand to ceramic, etc. The consequent impacts of these variations on well completion pressure responses and long-term production have been mixed. As part of the work covered in this paper, the differences between various completion methodologies and their impact on the stimulation strategies have been discussed in a chronological order. Although there is no single optimized design for the entire basin, experimentation of multiple methods and technical interpretation of various fracture and production models have provided us with a strong foundation to narrow down our practices to the most successful and repeatable ones across all the fields in the Bakken and Three Forks formations. The paper also covers how real-field measurements such as diagnostic fracture injection tests (DFITs), microseismic data, radioactive or chemical tracers, bottomhole pressure gauges, and interference experiments combined with log measurements such as magnetic resonance, acoustic logs, and elemental spectroscopy can provide us with a strong base for building and calibrating reservoir models that are reliable and reasonable. The paper covers technical differences between sliding sleeves and plug-and-perf completions; differences between crosslinked, slickwater, and hybrid designs and their impact on fracture geometries; effect of using different proppant types; and ways to optimize the number of fracturing stages and proppant and fluid volumes. As part of the study, the importance of geomechanics in understanding planar versus complex fracture geometries is discussed to close the loop with reservoir simulation models.
Abstract The recent slump in oil prices has given rise to a new term—drilled uncompleted (DUC) wells. In 2013 and 2014, when oil prices were above USD 100 a barrel, rates of return (ROR) from most unconventional plays were in the range of 15% to 50% depending on the quality of rock and the operator's portfolio in the basin. When oil prices fell drastically in November 2014 and continued its collapse, operators started building significant inventories of wells that were drilled but not completed. Most of these wells were drilled to honor drilling contracts, lease obligations, and promises made to investors to maintain production levels. The total number of DUC wells in the US is estimated to be greater than 5,000. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought online for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells. These concerns include fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). In case studies, real-time observations made from wells were used to validate predictions from forward-looking fracture and production models. Four guidelines to effectively develop DUC wells emerged from the study. First, fracture hits have been commonly observed in all unconventional plays throughout the US, with the effects on offset wells being mixed. Some fracture hits result in a positive uptick in production from offset wells whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, etc. Understanding fracture hits and their influences on other wells is very critical to optimize completion designs in DUC wells to avoid any detrimental impacts or leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on a variety of factors including, but not limited to, length of production history and parent completion geometries from offset wells. The longer the productive half-length and the number of years nearby wells have been on production, the lower the volume of oil available to produce for the DUC wells. In such cases, completion designs should be optimized to create more closely spaced, short fractures to accelerate hydrocarbon recovery. Third, in basins where there are multiple producing horizons or formations, fracture height growth and interference between adjacent formations can result in asymmetric fracture propagation towards depleted zones. The longer these wells completed in adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluating its impact on fracture geometries in DUC wells. Additionally, repressuring parent wells through recompletions to reduce asymmetric effects should be considered. Fourth, in areas with high-density drilling where spacing between wells is 660 ft or less, the combination of longer production and fracture stages with multiple perforation clusters per stage can leave very little oil available to produce for the DUC well. The paper discusses the drastic decline trends in production rates in such cases due to a combination of lower pore pressure gradient (from depletion) and resistance to fluid flow due to fracture interference. All four factors described above have been demonstrated in this paper in the form of different case studies in the Williston basin to provide the readers with a much broader view of the major challenges that will be critical to understand when these DUC wells are completed.