Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Yang, Xinping (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Li, Xiaoshan (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Hu, Die (University of Calgary) | Wu, Yushu (Colorado School of Mines) | Peng, Yan (China university of Petroleum, Beijing)
Re-fracturing of a horizontal well is a method to restore the productivity of the well in unconventional reservoirs after the expected production decline. Consequently, a re-fracturing approach may be necessary to improve/enhance production and ultimate recovery. However, there are many challenges for optimizing re-fracturing treatment design, due to lack accurate quantification of depletion-induced pressure and local stress change around fractures. The workflow presented can be applied to study and optimize a re-fracturing job to prevent potentially catastrophic fracture hits during re-fracturing operations.
In this paper, an integrated re-fracturing workflow was created and applied to determine the optimum re-fracturing strategy for multi-wells pad. This comprehensive workflow represents a multidisciplinary approach that integrates complex hydraulic fracture models, geomechanical models, and multi-well production simulation. The approach is able to couple simulated 3D reservoir pressure with a geomechanical model to quantify depletion-induced stress and pressure field change. Then, the altered stress field is utilized as the input for modeling the new fracture system created by the re-fracturing treatment. Two field cases from a tight oil reservoir are evaluated by comparing the model prediction to the pressure response. The model prediction agrees well with the observed pressure response and surface tiltmeter observations. The synthetic cases of interference between wells due to stresses and fracture design (number, placement and timing) are investigated in this work. A systematic sensitivity study is performed on the effects of re-fracturing time, fracturing spacing.
It is shown that quantification of stress field changes during reservoir depletion provides new insights for the design and evaluation of re-fracturing treatments to enhance field development. There is a critical time in the life of the well that protection refrac could help pressurizing the formation directly by increasing pore pressure through fluid injection and indirectly by mechanical dilation of existing fractures. The dynamic changes of stress field can guide the optimization of re-fracturing mode and zipper fracturing to reduce stress shadow effect. The dynamic change of the pressure field optimizes the fracturing fluid volume, which can increases the volume of the fracture transformation and supply formation energy.
The paper presents aN approach in calculating stress changes and dynamic fracture propagation into depleted region over time. Results obtained by this study give better understanding about propagation of new fractures as well as old fractures in re-fracturing process.
Lei, Zhengdong (The Research Institute of Petroleum Exploration and Development) | Wu, Shuhong (The Research Institute of Petroleum Exploration and Development) | An, Xiaoping (Exploration and Development Research Institute of Petro China Changqing Oilfield Company) | Zhu, Shengju (Exploration and Development Research Institute of Petro China Changqing Oilfield Company) | Zhu, Zhouyuan (China University of Petroleum) | Hu, Die (China University of Petroleum) | Liu, He (China University of Petroleum)
Multi-stage fractured horizontal wells have been successfully implemented in tight oil reservoirs. It is often observed that oil production declines rapidly in unconventional reservoirs. Consequently, re-fracturing may be necessary to improve/enhance oil production and ultimate recovery. However, many challenges exist in optimizing re-fracturing treatment designs, due to lack of accurate quantification of depletion-induced pressure and local stress changes around the fractures. We propose a workflow here to study and optimize re-fracturing job to increase reserves utilization level and energy level.
We present a comprehensive approach that integrates discrete-fracture, geomechanics, and multi-well production simulation models. First, the approach couples the simulated 3D reservoir pressure with a geomechanical finite-element model (FEM) to quantify the changes in the magnitude and azimuth of the in-situ stresses from the development process. Second, the altered stress field is utilized as the input for modeling the new fracture system created by the re-fracturing treatment. In addition, the finite element method is used in the calculation in the coupled reservoir flow and geomechanics model. And a unique full 3D unstructured mesh generation method effectively is adopted to simulate the longitudinal propagation of fracture. The synthetic cases of interference between wells due to stresses and fracture design are also investigated in this work. Furthermore, a systematic sensitivity study is performed for the effects of re-fracturing mode, formation pressure and matrix permeability.
The model prediction agrees well with the observed pressure response and microseismic event results. Results show that quantification of stress field changes during reservoir depletion provides new insights for the design and evaluation of re-fracturing treatments to enhance field development. There is a critical time in the well life that protection refracture could help pressurize the formation directly by increasing the pore pressure through the fluid injection, and indirectly by mechanical dilation of existing fractures, respectively. The dynamic changes captured timely in the stress field are invaluable to guide the optimization of re-fracturing mode for reducing the stress shadow effect. The dynamic change in the pressure field can be utilized to optimize the fracturing fluid volume, which can increase the volume of the fracture transformation and supply formation energy. This comprehensive approach is demonstrated to be very practical and effective in enhancing oil recovery, achieving satisfactory re-fracturing results.
The paper presents a novel approach in calculating stress changes and dynamic fracture propagation during the development of tight oil reservoirs. This work provides better understanding on the propagation of new fractures as well as old fractures during re-fracturing process, which serves as a great potential solution to improved oil recovery in tight oil reservoirs.
One of the most common field development plans in shale plays involves drilling lease/acreage retention wells in different areas followed by coming back and drilling infill wells. In majority of these shale plays, job sizes for hydraulic fracturing treatment are getting bigger over time in order to achieve more volume as well as value. However, due to depletion, there exists a pressure sink around the older existing producers and that significantly increases the possibility of older well getting "frac-hit" by new stimulation, and receiving large volume of frac fluid. Frac-hits can easily be seen using pressure gauges in older wells, and other surveillance techniques including chemical/RA tracers, microseismic, etc. One of the other "interference" effects that change the behaviour of parent well is refracturing. Operators are identifying candidates that were either poorly stimulated initially or have lost productivity over their life, and are refracturing those wells. In both frac-hits and refracs, there is a change in well productivity; and understanding and quantifying this loss/gain in production still remains challenging.
In this paper, both analytical and numerical modeling techniques were used to explore the existing workflows and techniques in the literature to study frac-hits and refracs. Rate transient analysis (RTA) was used to complement the numerical reservoir simulation models. Flow regimes were identified on superposition time plots using RTA (linear flow regime, boundary-dominated regime), and numerous sensitivities were run on the frac-hit/refrac timing, reservoir matrix permeability. Frac-hit examples from Eagle Ford shale were examined.
This paper studies the existing RTA techniques to model frac-hits/refracs and compares them with the new technique proposed herein. It was observed that RTA models needed to be re-initialized to model post frac-hit or refrac behaviour to correctly quantify the changes in SRV. It is shown that although the existing techniques work reasonably well at low matrix permeability, the error margin goes up as the permeability increases. In Eagle Ford, the permeability is high enough to warrant using this new analysis method.
Existing analyses methods primarily use diagnostic plots (superposition time) and are only applicable to frac-hits or refracs prior to boundary dominated flow (BDF) regime. This proposed method is valid over different flow regimes & larger permeability ranges. The analysis method recommended in this study allows the operators to better analyse the efficiency and benefits of their refracs, as well as detrimental impact of frac-hits from infilling and downspacing the wells.
Stimulated shale wells show sharp decline rates after several months of production imposing the need for rejuvenating production via re-fracturing or other methods. The sharp decline in production from shale gas/oil wells is attributed to full or partial closure and damage of the induced fracture network within the rock. The poor economic conditions stirred by low oil prices has persuaded operators to consider re-fracturing as an affordable option but the mechanisms behind this technique is not fully understood. In this paper, we utilize a fully coupled model to understand stress re-distribution and identify different modes of fracture closure during production from initial hydraulic fractures. Rock creep, proppant failure and differential fluid depletion are identified as primary causes of closure within shale fracture networks. We incorporate these phenomena into a poroelaso-plastic model that simulates fracture conductivity evolution during production, and re-fracturing treatments illustrated by re-fracture propagation, fracture coalesce or fracture extension along pre-existing fractures. This methodology provides a realistic initial condition to simulate varying re-fracture designs - different treatment schedules and fracturing fluids. The Influence of degradable mechanical and non-mechanical diverters is also incorporated in this model.
Our results reveal major stress redistribution in the fracture network especially at the intersections due to depletion. The results show how fracture closure at the fracture intersections causes abrupt or time dependent shrinkage of the drainage area. Under certain conditions, re-fracturing may effectively open up these bottlenecks while in extreme situations, it creates new fractures which reorient obliquely. Results also reveal the role of in-situ stress anisotropy, magnitude of depletion and complexity of fracture networks in the successful re-fracturing of lower- clay content naturally fractured formations such as the Barnett shale. The results do not suggest strong dependency on stress anisotropy and natural fractures orientation in high clay content reservoir rocks like Haynesville or Marcellus. It shows the quantifiable effect of creep on closure rate and conductivity loss. Results show diverters have a profound effect on the expansion of the re-fracture network, although it hinders reactivation of some clogged fractures. Using adaptive cohesive elements provides the opportunity to model longitudinal, transverse or oblique re-fracture propagation.
The Proposed model introduces a realistic fracture closure mechanism and stress re- distribution during drainage, prior to re-fracturing. This plays a vital role in explaining initial fracture extension, re-frac propagation, fracture coalesce, re-fracture re-orientation, and therefore the effectiveness of re-fracturing treatments. This model offers a practical tool for identifying potentially successful re-fracturing candidates.
Urban, Edgar (University of Calgary) | Orozco, Daniel (University of Calgary) | Fragoso, Alfonso (University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (University of Calgary)
Multi-stage hydraulic fracturing (HF) of horizontal wells is at the heart of successful oil and gas production performance from tight and shale reservoirs.
Fractures generated during the initial HF completion and natural fractures, tend to close as a well goes on production due to the increase of net stress on the fractures. The fractures closure reduces permeability and consequently productivity of the stimulated well. This study shows that under favorable conditions the production performance of the well can be revitalized with the use of a refracturing job. But there are key questions that need to be addressed: (1) When is the optimum time for refracturing? (2) What is the increase in permeability, production rate and cumulative production performance that can be expected from the refracturing job? (3) Is it better to refracture the well or to drill an infill well?
This paper addresses those three questions by considering multi-porosities known to exist in shale reservoirs. This includes inorganic matrix porosity (ϕm), natural fractures (microfractures and slot porosity, ϕ2), organic porosity (ϕorg) and adsorbed porosity (ϕads_c). In addition, hydraulic fracturing generates porosity around the wellbore (ϕhf). These porosities form a quintuple porosity system that is further fed by gas dissolved in solid kerogen.
The porosities mentioned above are included in a material balance that is combined with fracture closure for generating a model that calculates the optimum time for refracturing. Production rates and ultimate recoveries from this model and observations of actual refracturing jobs are compared with results from infill drilling. By considering the same reservoir properties and exactly the same hydrocarbons in place the conclusion is reached that refracturing has the potential to be more cost effective as compared with infill drilling.
The novelty of the approach is the development of an easy to use production performance method that can be reproduced readily in a spread sheet for calculating optimum re-fracturing time, production rates, and cumulative recovery; and for making quick comparisons of the benefits of refracturing vs. infill drilling in shale reservoirs. Results of the easy to use material balance are corroborated with a state of the art commercial reservoir simulator.
Microseismic monitoring of refracturing of depleted horizontal wells frequently shows a concentration of microseismic activity at the heel area when no mechanical isolation is used. This observation suggests that a considerable length of the well toward the toe does not benefit from refracturing and remains unstimulated. Different completion techniques, ranging from injecting diverters to using mechanical intervention methods, are usually used to avoid the localized stimulation and to enhance the treatment effectiveness. However, often overlooked is the effect of the reservoir rock's mechanical characteristics and how they contribute to the treatment results.
In this study we investigated the potential contributing factors to the observed microseismic response: i) fluid pressure drop along the lateral, ii) diverter ineffectiveness, and iii) stimulation of pre-existing fractures versus developing fresh fractures from new perforations. Estimation of pressure losses along the well for the common casing diameters and fracturing fluids indicates that a high pressure gradient develops along the well during refracturing. It results in significantly higher injection pressures at the heel than at the toe, leading to higher discharge rates at the heel. If the added diverters fail to seal off the perforations at the heel area, this condition persists throughout the treatment and causes the localized stimulation of the rock, as is usually observed by microseismic monitoring.
The numerical simulation of refracturing indicates that under a non-uniform treatment pressure profile and in the absence of effective diverters, the initiation and propagation of new hydraulic fractures is unlikely. The dominant stimulation mechanism is the shear failure of natural fractures, driven by the increase of fluid pressure by injection of fluid through the old perforations. This result is consistent with the observed long delay in microseismic response to refracturing and the increasing event counts as pumping continues.
Based on these findings, we developed an alternative refracturing method that aims at increasing the reservoir effective complexity and enhancing the conductivity of the pre-existing hydraulic fractures uniformly along the well. The proposed method consists of a prolonged low-pressure and low-rate pad stage to pressurize the reservoir, followed by a high-pressure injection stage to stimulate the pressurized natural fractures and to place proppant in the new fractures. Critical to the success of this method is to avoid a high pressure contrast along the well. This can be achieved by proper selection of injection pressure and fluid viscosity with respect to the reservoir stresses and pressure, and the well characteristics. Numerical simulations indicate that the proposed method can considerably enhance the efficiency of refracturing, at no additional cost compared to the common refracturing methods.
Production performance for unconventional shale reservoirs generally show an early high flow rate followed by a steep decline. Refracturing the underperforming wells is an economical practice to mitigate the flow rate decline and maximize reservoir deliverability, especially at the current low oil price environment. Selecting the correct candidates for refracturing is a crucial step for refracturing jobs. Despite the experience that has been gained in refracturing candidate selection for conventional reservoirs and unconventional tight reservoirs, very little literature is currently available about refracturing candidate selection for multistage hydraulic fractured horizontal wells.
An efficient refracturing candidate selection approach is proposed in this paper based on competition between the produced volume and the drainage volume. The well drainage volume is calculated based on pressure and production data, which measures how much reservoir volume is accessed by the well. Instantaneous Recovery Ratio (IRR), defined as the ratio of produced volume to the drainage volume, is proposed in this paper to measure how quickly or efficiently the accessed volume is being produced. Wells are qualitatively ranked based on their drainage volume and IRR after sufficient production time. Accordingly, well production performance can be compared and refracturing candidates can be selected.
Proposed drainage volume calculation and IRR can efficiently measure the effectiveness of fracture stimulation. The proposed refracturing candidate selection approach is first validated through coupled fluid flow and geo-mechanical simulation, which can account for stress shadow and stress change due to depletion for modeling of the refracturing process. Candidate selection approach is then applied to Eagle Ford shale wells. Results suggest that maximum potential candidate seems to be the well with relatively large drainage volume but with poor depletion rate.
The advantage of the proposed approach is that all calculations are based on pressure and production data, which is purely data driven without any presumptive flow regimes. The result of our refracturing candidate selection criteria is compared to that of previous approaches based on production and completion indices. The proposed approach by this paper can select consistent underperforming wells but additionally can differentiate the wells by giving possible underlining reasons for underperforming. Thus, more appropriate refracturing jobs can be designed accordingly to maximize the chance of refracturing success.
In this paper, a brief review of a study of pressure dependent SRV region that takes shape during water injection in the fracturing process and reduces in size during production is presented. The pressure depletion and natural fracture permeability distribution pattern derived from this reservoir simulation analysis will help understand the feasibility of re-fracturing. The phenomenon of shear dilation, resulting in self-propping of natural fractures due to irregularities present on the rock surface, is captured in this study through the use of a dilation rock model for the natural fractures which acts as an effective geomechanical proxy.
The natural fractures were assumed to be closed at the start of the water injection process during fracturing and their initial permeability was assumed to be equal to that of the matrix in the virgin rock. As water was injected during the hydraulic fracturing operation, permeability of the natural fractures increased marginally with pressure until the fractures became critically stressed (at the shear dilation onset pressure). Beyond the shear dilation onset pressure, the natural fracture permeability increased rapidly with pressure. This gave rise to a dynamic SRV around the hydraulic fractures. Based on this concept, a simulation model was constructed and history matched to an existing Eagle Ford well producing from the oil window with 19 stages, after which a re-fracture was simulated. Sensitivity analysis was done to bracket the range of incremental EURs that can be obtained upon re-fracturing.
The results of the history matched model showed an elliptical SRV region around each hydraulic fracture that dissipates over time during production. Also, it was found that an inversion of natural fracture permeability takes place as the pressure decreases first near the wellbore during production. Pressure depletion shows that there is a significant amount of oil saturation left between the fractures. This provides the rationale for re-fracturing between existing fractures, which may not be possible at the time of first completion due to stress shadow prohibiting closer spacing. The forecast production shows a significant increase in the EUR upon re-stimulation.
The industry is already looking at re-fracturing as an alternative to drilling new wells to increase their reserves and this study ties in to that need to explain the why and the how of the re-fracturing process.
Diakhate, Mamadou (Pioneer Natural Resources) | Gazawi, Ayman (Pioneer Natural Resources) | Barree, Robert David (Barree & Associates) | Cossio, Manuel (Pioneer Natural Resources) | Tinnin, Beau (Pioneer Natural Resources) | McDonald, Beth (Pioneer Natural Resources) | Barzola, Gervasio (Pioneer Natural Resources)
This paper outlines a REFRAC pilot testing program conducted in the Eagle Ford shale.
As wells in the Eagle Ford accumulate production over time and the pressure around the horizontal wellbore declines, it is important to protect the wells and associated reserves from any offset fracture stimulation and communication that could potentially cause damage. Re-fracturing trials in older fields such as the Barnett have yielded a positive enhancement of the well performance. This paper gives an evaluation in the eagle ford of the effectiveness of the refrac on protection of the older wells.
Actual refracturing pumping data from this field is used to demonstrate the type and mechanism of fracture reorientation
Re-fracturing an old horizontal well with 5000 ft. lateral length and more than 800 existing perforation holes in the casing is very challenging and does require a careful integration of reservoir knowledge, completions skills and experience. The technical team of Pioneer Natural Resources has developed an integrated workflow to design and execute a re-fracturing job for an Eagle Ford well. The work flow include: 1) Reservoir study to identify the lower pressure areas along the lateral. This is done by integrating all the surveillance data from the well such as micro-seismic, tracer logs, production data. 2) Identify wells within the drilling schedule that are offsetting older unit primary wells with high cumulative production. 3) Design of a single fracturing job with several sub-stages separated by diverting agents. Volumes and pump schedules will be specific for each candidate based on proximity to offset well, lateral length, and existence of geological structures. The candidate wells in the pilot program will be re-fractured and the re-fracturing field execution procedure will be adjusted based on lessons learned from this pilot experimentation. The results from these pilot wells when looking at the fracture gradient changes before and after refrac, the radio-active tracers and well performance will be evaluated following field execution.
"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.