This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.
Eagle, L. M. Holding (Nalco Champion, an Ecolab Company) | Spicka, K. J. (Nalco Champion, an Ecolab Company) | Fidoe, J. (Nalco Champion, an Ecolab Company) | Jordan, M. M. (Nalco Champion, an Ecolab Company)
It has been proven that scale squeezes can be conducted effectively in the unconventional, horizontal fractured wells in the shale reservoir of the Bakken when using an optimal scale squeeze chemistry. Previous work has discussed inhibitor selection and performance testing along with early case histories and modeling work. This paper discusses new case histories and Place-iT modeling results based on several procedural variations including a range of overflush volumes in the squeeze treatment procedure and the inclusion of acid cleanouts.
Novel, reduced-volume squeeze designs have successfully protected wells from scale deposition while limiting the direct and indirect costs associated with extra placement water. For unconventional shale wells in the Bakken, where produced water is typically very high in TDS and TSS, fresh water is most commonly used to execute squeezes. Reducing the total water volume reduces the costs of purchasing, transporting and storing fresh water. The amount of time and cost to pump the job is decreased. Less time and money is spent lifting the placement water, and consequently, there is less deferred production. In addition, in unconventional production acid treatments are commonly carried out in isolation to maintain production. In this work, applying acidizing stages at the front of the squeeze procedures, provides a novel "squimulation" process to fractured reservoir scale control treatments.
For these unconventional horizontal wells, the use of larger water volumes—either several times full wellbore volume and/or several times daily water production—has not been shown to improve the longevity or cost-effectiveness of squeeze jobs. Contrary to conventional well applications modeled with Darcy flow, it appears diffusion is the more applicable mechanism for scale inhibitor transport in fractured shale wells. This mechanism is consistent with a reduced dependence on water volume deployed in the treatments.
The lessons learned from the unconventional horizontal scale squeezes conducted in the Bakken have resulted in enhanced production and cost savings. There are significant implications for the industry as other key unconventional regions in the U.S. and around the world are looking into scale squeezes as an option for scale control.
We offer a preliminary assessment of the sensitivity of Bakken oil production to a variety of factors using the model from Ikonnikova et al (2017). The oil price is probably the single most important factor that can drive cumulative Bakken production (2015-2045) up or down as much as 50%. Other factors such as the implementation of technology that can reduce costs, increase productivity, or both also impact the production outlook but less than the oil price. However, these factors require further investigation to confirm the reasonableness of the ranges we tested, and, more importantly, to better represent the interactions among costs, productivity, and the oil price. Scenarios that combine multiple factors and capture these interactions are likely to yield more realistic outlooks.
The Bakken play has been one of the major contributors to U.S. oil production growth although the active development started only in the second half of the 2000s, encouraged by historically high oil prices through 2008 and building on the success of unconventional drilling in other plays. The introduction of horizontal drilling and hydraulic fracturing technologies allowed operators to increase production in Bakken, where limited conventional development have been pursued for a long time. The temporary drop in the oil price in 2009 did not have much impact on drilling activity but the collapse of the oil price in late 2014 and sustained low prices stopped production growth by mid-2015.
The play economics and potential future development in Middle Bakken and Three Forks horizons was analyzed in another study by our team presented in this conference (Ikonnikova et al., 2017). The present study subjects the base production outlook to some sensitivity testing. All of these results should be considered preliminary as we continue with our analysis as more data becomes available and we test more sensitivities. Key factors that are discussed in this abstract are prices and costs.
We present a preliminary assessment of the Bakken oil Well Economics and Production Outlook. The price of oil is the major driver for drilling, but not the only one, as suggested by our analysis. Other parameters such as oil gravity, well drilling and completion costs, technology used, input factor productivity, presence of Three Fork in addition to Bakken drilling horizon can affect both well economics and expected production outlook. This paper presents the model developed to run production‐outlook scenarios varying assumptions on the listed parameters.
The last period of rising oil price that started in 2009 was the key driver for nearly exponential growth of the U.S. crude oil production. With the collapse of the oil price in late 2014, production growth stopped by mid‐2015. The active development of the Bakken oil play started over a decade ago with the introduction of horizontal drilling technology. The play has been one of the major contributors to U.S. production growth. Until recently, it was considered the biggest in terms of oil‐in‐place, now it stands second after the Permian Basin. It is important to understand the play economics and potential future development in this significant play. The present study investigates two key questions:
Hui, Peng (Research Institute of Petroleum Exploration and Development) | Qiquan, Ran (Research Institute of Petroleum Exploration and Development) | Yong, Li (Research Institute of Petroleum Exploration and Development) | Min, Tong (Research Institute of Petroleum Exploration and Development)
Fractured horizontal wells are widely used to produce tight oil. But different fracture patterns could be generated in different reservoirs, which results in different well performances. How to identify the flow regimes and their impacts on performance is still challenging. This paper provides a method for flow regime identification of horizontal wells with different hydraulic fracture patterns in tight reservoirs.
First, four different fracture patterns of hydraulically fractured horizontal wells in different types of tight oil reservoirs are classified, according to the fracture network identified from micro-seismic observation and laboratory experiments. Then, corresponding well performances are simulated based on various conceptual reservoir simulation models. The simulation results are further used for rate transient analysis. Finally, flow regimes and corresponding production periods of each pattern are identified and classified, and well performances are also analyzed.
Flow regimes of different fracture patterns are identified based on rate transient analysis with input of reservoir simulation results. Different patterns have different flow regimes. For instance, there are linear flow, radial flow and boundary dominated flow in Pattern A, while bilinear flow, linear flow, radial flow and boundary dominated flow are prevail in Pattern C. The corresponding production phase of each flow regime is also classified. It can be seen that different scales of pores and fractures have different impacts on different patterns and production phases. In pattern A and Pattern D, large fractures determines the initial production rate and performance of linear flow, and more oil is produced in linear flow stage than in radial and boundary dominated flow periods. While in Pattern B and Pattern C, micro-nano fractures and pores are much more developed, which have more cumulative production and better performances during radial flow and boundary dominated flow.
The results are applied to the tight oil reservoirs in Junggar and Erdos Basin in China. Analysis of all fractured horizontal wells indicates that most are pattern A and Pattern B, and linear flow occurs in the early production period in all the patterns. If hydraulic fractures are long enough, bilinear flow could happen. Well performances are correctly predicted based on the well flow regime identification.
Since the late 1980s when Maersk published their work on multiple fracturing of horizontal wells in the Dan field, the use of transverse multiple-fractured horizontal wells has become the completion of choice and the “industry standard” for unconventional and tight-oil and tight-gas reservoirs. Today, approximately 60% of all wells drilled in the United States are drilled horizontally, and nearly all are multiple-fractured. However, little work has been performed to address and understand the relationship between the principal stresses and the lateral direction. This paper has as its goal to fundamentally address the questions: In which direction should I drill my lateral? Do I drill it in the direction of the maximum horizontal stress (longitudinal), or do I drill it in the direction of the minimum horizontal stress (transverse)?
This work focuses on how the horizontal well’s lateral direction (longitudinal or transverse fracture orientation) influences productivity, reserves, and economics of horizontal wells. Optimization studies, with a single-phase fully 3D numerical simulator including convergent non-Darcy flow, were used to highlight the importance of lateral direction as a function of reservoir permeability. The simulations, conducted for both oil and gas formations over a wide range of reservoir permeability (50 nd–5 md), compare and contrast the performance of transversely multiple-fractured horizontal wells with longitudinally fractured horizontal wells in terms of rate, recovery, and economics. This work also includes a series of field case studies to illustrate actual field comparisons of longitudinal vs. transverse horizontal well performance in both oil and gas reservoirs, and to tie these field examples to the numerical-simulation study. Further, the effects of lateral length, fracture half-length, and fracture conductivity were investigated to see how these parameters affect the decision of lateral direction in both oil and gas reservoirs. In addition, this study seeks to address how completion style (openhole or cased-hole completion) affects the selection of lateral direction.
The results show the existence of a critical reservoir permeability, above which longitudinal fractured horizontal wells outperform transverse fractured horizontal wells. With openhole completions, the critical permeability is 0.04 md for gas reservoirs and 0.4 md for oil reservoirs. With cased-hole completions, longitudinal horizontal wells are preferred at a reservoir permeability above 1.5 md in gas reservoirs, and transverse horizontal wells are preferable over the entire permeability range of this study (50 nd–5 md) in oil reservoirs. These are new findings. Previous work generally suggested that longitudinal horizontal wells are a better option for gas reservoirs with permeability over 0.5 md, and for oil reservoirs with permeability over 10 md.
This work extends prior study to include unconventional reservoir permeabilities. It provides critical permeability values for both gas and oil reservoirs, which are validated by the good compliance between actual field-case history and simulation results. This work also demonstrates a larger impact of completion method over fracture design. These findings could guide field operations and serve as a reference for similar studies.
Multi-cluster staged fracturing is an effective method to exploit shale gas. Field observations reported some clusters did not generate fractures. X5 formation in Sichuan Basin is a 3000m deep shale reservoir. The horizontal stress difference is so high, therefore it is difficult to generate fracture network. How to enable all fractures propagate effectively from each cluster and generate enough stress interference to enable fracture network is of critical concern.
This paper established a 3D fracture propagation model based on finite-element method to simulate multi-cluster fracturing of X5 reservoir. The fracture propagation model couples seepage-stress-damage theories to simulate fracture propagation. The cohesive element is used to simulate the forming of fracture, and the filtration from fracture to matrix is taken into consideration. This model is used to study three fractures propagating simultaneously from three clusters. Six different cluster spacing cases were simulated to investigate the fracture geometry and the stress field.
The research finds that when the cluster spacing is 10m, 20m, 30m and 35m, the length of the middle fracture is severely restricted; but for the side fractures, the length is over propagated. When the cluster spacing is 40m and 50m, balanced propagation of all the three fractures is achieved. In the 10m, 20m, 30m, 35m and 40m cluster spacing cases, the horizontal stress ratio is low and could generate fracture network, but the 50m case could not. By considering the fracture geometry and stress ratio, the optimized cluster spacing is 35m-40m. Based on this optimization, a 7-stage fracturing treatment of X55 well was designed and conducted. The treatment process was smooth and its production was 1.7 times the average production of the adjacent horizontal wells.
This paper presented a method to optimize the cluster spacing by both considering the fracture geometry and stress ratio. Cluster spacing optimized by this method could enable the effective propagation of all main fractures and increase the possibility of generating fracture network.
Shale operators are finding it increasingly critical to find a reservoirs' sweet spot, choose the optimum landing point, geo-steer the well within the best rock, and run the optimal completion hardware in order to exceed investor expectations. Due to geological structures that vary across the field or geo-steering quality issues, many wells suffer severe sinuosity which potentially impairs completions and inhibits productivity. This study presents a comprehensive evaluation of hydraulically-fractured wellbore productivity compared with relatively smooth and highly-sinuous wells of similar reservoir quality. The sharp contrast leads to the engineering investigation by coupling a reservoir model which imbeds a representative complex fracture network with a transient multiphase wellbore simulator. The integrated model provides insight behind the flow instability in horizontal wells that produce hydrocarbons from unconventional reservoirs and the remedy completion and production strategy by considering reservoir and wellbore coupled performance. Hydraulically-fractured horizontal wells in shale reservoirs have unstable flow dynamics because of low effective productivity index, small fluid velocity (due to large production string), and multiphase flow under bubble-point pressure, etc. We found that all these reasons lead to vigorous terrain slugging for any toe-up or toe-down wellbore geometries. Furthermore, this flow assurance issue determines more serious problems while encountering a certain level of wellbore sinuosity. In fact, we observed how the stagnation of fluid may isolate entire sections of the lateral and lead to a huge impairment of well deliverability.
The acquisition of accurate downhole pressure measurements from land-based unconventional wells can enable analysis of pressure data that can be used to help optimize and reduce the cost of fracture treatments and improve overall well productivity. The pressure data for the analysis are obtained from downhole electronic gauges in both the target well and in the surrounding observation/monitoring wells. The objective of this paper is to demonstrate the value monitoring this downhole pressure data can provide throughout the life of land-based unconventional wells. The paper also describes the selection of the equipment, the steps necessary for its successful installation, project commissioning, and acquisition of reliable data throughout the life of the well. Historically, operators have experienced less-than-desirable success rates for long-term downhole pressure monitoring, especially in multizone, openhole, horizontal wells. This paper discusses how the success rate of these installations has been significantly improved by the implementation of a program with a well-defined series of steps that includes detailed planning (completing the well on paper exercise), onsite function testing of equipment prior to installation, and stringent attention to job execution detail. This program is based on the fact that adoption of the proper selection criteria for the application is critical to selection of the proper type of monitoring equipment and to the operational and economic success of these pressure-monitoring projects.