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Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Abstract A unique well-tracing design for three horizontally drilled wells is presented utilizing proppant tracers and water- and hydrocarbon-soluble tracers to evaluate multiple completion strategies. Results are combined to present an interpretation of them in the reservoir as a whole, where applicable, as well as on an individual well basis. The new approach consists of tracing the horizontal well(s) leaving unchanged segments along the wellbore to obtain relevant control group results not available otherwise. The application of the tracers throughout each wellbore was designed to mitigate or counterbalance variables out of the controllable completion engineering parameters such as heterogeneity along the wellbores, existing reservoir depletion, intra- and inter-well hydraulically driven interactions (frac hits) as well as to minimize any unloading and production biases. Completion strategies are provided, and all the evaluation methodologies are described in detail to permit readers to replicate the approach. One field case study with five horizontal wells is presented. Three infill wells were drilled between two primary wells of varying ages. All wells are shale oil wells with approximately 7,700 ft lateral sections. The recovery of each tracer is compared between the surfactant treated and untreated segments on each well and totalized to see how the petroleum reservoir system is performing. A complete project economic analysis was performed to determine the viability of a chemical additive (a production enhancement surfactant). Meticulous analysis and interpretation of the proppant image logs were performed to discern the cluster stimulation efficiency during the hydraulic fracturing treatments. Furthermore, comparisons of the cluster stimulation efficiency between the two mesh sizes of proppant pumped are also provided for each of the three new unconventional well completions. The most significant new findings are the surfactant effects on the wells’ production performance, and the impact the engineered perforations with tapered shots along the stages had on the stimulation efficiency. Both the right chemistry for the formation and higher cluster stimulation efficiencies are important because they can lead to increased well oil production. The novelty of this tracing design methodology rests in the ability to generate results with a statistically relevant sample size, therefore, increasing the confidence in the conclusions and course of action in future well completions.
Ajisafe, Foluke (Schlumberger) | Reid, Mark (Lime Rock Resources) | Porter, Hank (Lime Rock Resources) | George, Lydia (Former employee of Schlumberger) | Wu, Rhonna (Former employee of Schlumberger) | Yudina, Kira (Former employee of Schlumberger) | Pena, Alejandro (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Artola, Pedro (Schlumberger)
Abstract Increased drilling of infill wells in the Bakken has led to growing concern over the effects of frac or fracture hits between parent and infill wells. Fracture hits can cause decreased production in a parent well, as well as other negative effects such as wellbore sanding, casing damage, and reduced production performance from the infill well. An operator had an objective to maximize production of infill wells and decrease the frequency and severity of frac hits to parent wells. The goal was to maintain production of the parent wells and avoid sanding, which had the potential to cause cleanouts. Infill well completion technologies were successfully implemented on multiwell pads in Mountrail County, Williston basin, to minimize parent-child well interference or negative frac hits on parent wells for optimized production. Four infill (child) wells were landed in the Three Forks formation directly below a group of six parent wells landed in the Middle Bakken. The infill well completion technologies used in this project to mitigate frac hits included far-field diverter, near-wellbore diverter, and real-time pressure monitoring. The far-field diverter design includes a blend of multimodal particles to bridge the fracture tip, preventing excessive fracture length and height growth. The near-wellbore diverter consists of a proprietary blend of degradable particles with a tetra modal size distribution and fibers used to achieve sequential stimulation of perforated clusters to maximize wellbore coverage. Hydraulic fracture modeling with a unique advanced particle transport model was used to predict the impact of the far-field diverter design on fracture geometry. Real-time pressure monitoring allowed acquisition of parent well pressure data to identify pressure communication or lack of communication and implement mitigation and contingency procedures as necessary. Real-time pressure monitoring was also used to optimize and validate the far-field diversion design during the job execution. The parent well monitored was 800 ft away from the closest infill well and at high risk for frac hits due to both the proximity to the infill well and depletion. In the early stages of the infill well stimulation, an increase in pressure up to 600 psi was observed in the parent well. The far-field diverter design was modified to combat the observed frac hit, after which a noticeable drop in both frequency and magnitude of frac hits was observed on the parent well. This is the first time the far-field diverter design optimization process was done in real time. After the infill wells stimulation treatment, production results showed a positive uplift in oil production for all parent wells at an average of 118%. Also, only two out of seven parent wells required a full cleanout, resulting in savings in well cleanup costs. Infill well production data was compared with the closest parent well landed in the same formation (Three Forks). At about a year, the best infill well production was only 10% less than the parent well with similar completion design and the average infill well production approximately 18% less than the parent well. Considering the depletion surrounding the infill wells, production performance exceeded expectations.
Khor, Guan Han (PETRONAS Carigali Sdn Bhd) | Razali, Ezuan Hanafi (PETRONAS Carigali Sdn Bhd) | Musa, M. Idham (PETRONAS Carigali Sdn Bhd) | Mat Isa, Saifol Anuar (PETRONAS Carigali Sdn Bhd) | Wan Hasan, Wan Helmi (PETRONAS Carigali Sdn Bhd) | Chang, Daryl (Cameron)
Abstract Since Conductor Sharing Technology became prominent in the 1990s, the technology has evolved to accommodate the associated well design and construction complexities. In the redevelopment of Brownfield "S", under an alliance between PETRONAS Carigali and other operator, the technology has enabled the number of potential new wells to be increased. However, the technology has been constrained in terms of the available conductor and casing size options. The objective is to advance the current technology to meet the well design and construction requirements. This paper presents the challenges and solutions for conductor sharing technology to accommodate a higher specification conductor (36"×1.5" wall thickness), which is required to meet the fatigue life requirement in Field "S" Phase 3 redevelopment project. Since mid-2018, when PETRONAS took over the operatorship, further conductor analyses have been required. These studies confirmed the requirement for 36" conductor with 1.5" wall thickness, to meet the target fatigue life of 20 years. This paper focuses on a range of key engineering considerations related to well construction including geometrical separation, integration between CWD (casing while drilling) and directional, cementing, and diverter requirement to CWD surface casing. Since there is no existing system that can accommodate this wall thickness and still be able to meet the well construction requirements, a collaboration with the equipment provider has led to the design and manufacture of the world's first splitter wellhead system used for 36" (1.5" WT) × 13-3/8"(2X) × 9-5/8"(2X) × 3-1/2"(4X) with 10,000 psi working pressure rating. The splitter wellhead has allowed two infill wells to be drilled and completed on Platform "A". The system has maximized oil recovery with the additional well. The successful installation and production from this wellhead provide opportunity to reduce construction cost and maximize utilization of existing well slots for future development of brown fields. The improved technology has created more value by allowing surface casing to be installed by CWD in directional sections and the cementing program to be enhanced under diverter system. This solution will be beneficial to similar brown fields which have limited remaining slots and where it is unjustifiable to construct a new platform. In addition, it provides opportunity to lower the wellhead platform cost for green fields by optimizing the number of well slots and platform design.
Zhu, Haiyan (Chengdu University of Technology) | Tang, Xuanhe (Chengdu University of Technology) | Song, Yujia (Southwest Petroleum University) | Li, Kuidong (SINOPEC Jianghan Oilfield Company) | Xiao, Jialin (SINOPEC Jianghan Oilfield Company) | Dusseault, Maurice B. (University of Waterloo) | McLennan, John D. (University of Utah)
Summary A microseismic (MS) events barrier (MSEB) phenomenon was detected during infill well fracturing of the Fuling shale gas reservoir. This phenomenon was evidenced by MS monitoring results, indicating that when the infill well hydraulic fracture (HF) propagated close to the parent well stimulated region, only a main straight fracture was propagating. Also, the number of seismic events diminished abruptly, suggesting some barrier or an attenuation process for the MS. To clarify the mechanisms involved in the MSEB effect, the infill well fracture propagation is investigated. An integrated workflow is proposed to analyze complex HF propagation of an infill well after the offset parent wells have experienced fracturing and production. The workflow integrates a geological model with natural fractures, a parent well fracturing geomechanical model, a coupled flow‐geomechanics production model, and an infill well fracturing geomechanical model. First, a natural fracture network is embedded in the realistic geological model. Second, a geomechanical fracturing model is developed to simulate HF of parent wells. Third, a coupled flow‐geomechanics model is used to analyze stress field evolution during parent well production. Fourth, complex HF propagation for the infill well is simulated. The case model is validated with parent well production data and infill well fracturing MS monitoring results. It can be concluded from the simulation results that (1) during parent well production, the pre‐existing complex fracture network is a major contributor to pore‐pressure decrease; (2) stress evolution is affected by the geomechanical heterogeneity; (3) near the parent well producing fractured region, the fracture complexity of the infill well stimulation decreases sharply and that matches well with the MS monitoring results; and (4) there are two primary mechanisms that are responsible for the MSEB phenomenon—natural fracture (NF) activation during parent well fracturing and stress evolution in parent well production. The Fuling shale gas reservoir infill well fracturing case study reveals the mechanism of the MSEB effect by demonstrating the impact of parent well production on infill well fracturing. To serve the fracture‐hits evaluation and to maximize the stimulated reservoir volume (SRV), the MSEB effect should be taken into consideration in infill well fracturing design.
In an era where capital markets are hitting the brakes on funding the US shale sector, operators have increasingly pivoted from production growth to maximizing the rates of return via lower-cost wells. One of the major challenges of this new era is the determination of optimal stage and well spacing for a drilling area. For much of the US, the trend has been toward increased job size and rapid downspacing of infill or "child" wells. The unintended consequence of this trend has been an increase in fracture interference and excessive cross-well communication, which results in an overcapitalization of acreage and underperforming child wells as the drainage areas of wells overlap and compete for depleted resources. Within the SCOOP/STACK play, child wells completed in 2017/2018 have been half as productive as their 2015/2016 parent wells, a trend theorized to be directly related to negative fracture interactions.
Summary Late in the life of the Steam Assisted Gravity Drainage (SAGD) process, it has become common practice to drill a single, horizontal infill well (called a “Wedge Well™” by some) in the oil bank located between two mature SAGD well pairs to produce the bitumen that has been heated and mobilized but is unable to be effectively drained by gravity given the largely lateral location relative to that of the SAGD producers. Since this oil bank is surrounded by the large, depleted steam chamber created by the existing well pairs, it requires little heat to mobilize bitumen. One of the challenges, however, in producing infill wells is that non-uniform drainage and local hot spots can be readily created in the first year of their operation, that in many cases require completion retrofits, such as with Flow Control Devices (FCDs), to improve the drainage profile. Installation of FCDs in these wells is quite challenging since the dynamics of the infill wells is changing with time and there is limited time to achieve conformance. To maintain pressure in SAGD chambers the common practice is to inject non-condensable gas (NCG). NCGs, such as methane, which is most common, do not condense in the steam chamber. Some of these NCG can short-cut into the infill through the existing hot-spot. The main reason is that the hot sections of infills are locations that are closer to the SAGD steam chamber, and due to steam condensate encroachment and higher mobility create a pathway for NCG breakthrough. FCDs are designed to promote a more uniform flux distribution along the producer, and exposure to NCG can change the impact of the FCDs. The true hot-spot temperature after NCG injection is decreasing and this can be mistaken as FCD efficiency and steam blocking. In reality, this temperature reduction is due to partial pressure effects associated with NCG encroachment. In this study, a new thermodynamic model is created to explain the NCG encroachment into infill wells, and a new temperature profile along the producer as a function of NCG breakthrough is calculated. The purpose of this work is to create a productivity index (PI) relationship that is fit for purpose for infill wells adjacent to SAGD well-pairs with NCG breakthrough that can primarily be used for analysis and optimization of SAGD FCD completions. This model can also be used to evaluate FCD performance in infill wells pre- and post- NCG breakthrough.
Hardcastle, Michael (Connacher Oil and Gas Limited) | Holmes, Ryan (Connacher Oil and Gas Limited) | Abbott, Frank (Connacher Oil and Gas Limited) | Stevenson, Jesse (Variperm Canada Limited) | Tuttle, Aubrey (Variperm Canada Limited)
Abstract Connacher Oil and Gas has deployed Flow Control Devices (FCDs)on an infill well liner as part of a Steam Assisted Gravity Drainage (SAGD) exploitation strategy. Infill wells are horizontal wells drilled in between offsetting SAGD well pairs in order to access bypassed pay and accelerate recovery. These wells can have huge variability in productivity, based on several factors: variable initial temperature due to variable steam chamber development and initial mobility variable injectivity from day one limiting steam circulation and stimulation significant hot spots during production that limit drawdown of the well and oil productivity FCDs have shown great value in several SAGD schemes and are becoming common throughout SAGD applications to manage similar challenges in SAGD pairs, but their application in infill wells is less prevalent and presents a novel challenge to design and evaluate performance. This case study will examine the theory, operation, and early field results of this field trial. Density-based FCDs designed for thermal operations were selected to minimize the impact of viscous fluids commonly encountered early in cold infill well production. The design also limited steam outflow during the stimulation phase, where steam is injected in order to initiate production of the well. Distributed Temperature Sensing (DTS) data, pressures and rates are utilized to analyze the impact of the FCDs towards conformance of the well in the early life. The value of FCDs has led to further piloting of this technology in a second group of nine infill wells, where further value is to be extracted using slimmer wellbores.
Behera, Chaitanya (Petroleum Development Oman) | Mahajan, Sandip (Petroleum Development Oman) | Annia, Carlos (Petroleum Development Oman) | Harthi, Mahmood (Petroleum Development Oman) | Obilaja, Jane-Frances (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.
Hot shale plays tend to fall short of expectations after a few years, and the Permian Basin will be the next big test of the pattern. A recent technical paper by Robert Clarke, research director for Lower 48 Upstream for Wood Mackenzie, questions whether future drilling in the Permian will hit 5 million b/d in 2025 as the consultancy has predicted. Based on what he has been learning recently, some of it reported in SPE technical papers, the actual results could be worse or better, depending on how well the industry solves the problems that will come with intensive development in the Permian. "There is a lot of exuberance in low-cost unconventional plays in their early years," he said on a recent podcast from Wood Mackenzie, adding, "In retrospect, the first 3 years of a shale play are easy, then it gets harder." While older plays such as the Marcellus and Bakken hit economic limits due to limited pipeline capacity, Clarke's big concern in the Permian is more geological.