Unconventional assets are crucial to the overall economic production of hydrocarbons. With the industry-wide trend of optimizing well spacing comes an increase in “frac hits”, i.e., adverse impacts on producing wells from stimulating a nearby well. Although in-zone frac hit events do not necessarily pose an environmental problem, data shows that existing, producing wells can be negatively impacted in a number of ways. Producing wells can be harmed when the pressure wave created during the hydraulic fracturing process is strong enough to cause pressure spikes or sand loading, either directly through fracture/fracture interactions or indirectly due to the propagating pressure wave reaching a nearby well drainage boundary with enough energy to cause damage. Consequently, finding ways to minimize the effect of fracture hits is currently a major focus in the oil and gas industry. In this paper, we consider an approach to mitigating frac hits that can be applied when initially performing acreage planning by ensuring sufficient well spacing during pad planning, or at stimulation time by limiting fracture lengths so that fractures do not directly interact with nearby producing wells.
Drilling, completing and stimulating unconventional wells requires significant capital investment. Because unconventional assets are becoming increasingly more important, there is an industry-wide tendency to maximize acreage production by optimizing well spacing in unconventional reservoirs. However, reduced well spacing has led to “frac hits”, here defined as unwanted interactions between a hydraulically stimulated well and a nearby producing well. Given the amount of in-fill drilling currently afoot in the industry (Vidma et al. 2019), and the number of future horizontal wells forecasted to be fractured (Cook et al. 2016; Perrin, et al. 2016; Cook et al. 2018), the issue of frac hits has become of significant concern. Field data demonstrates that producing wells can be negatively impacted in several ways. For example, the pressure wave created during the hydraulic fracturing process can interact with the existing well drainage boundary either directly or indirectly. Direct interactions include fracture/fracture interactions such as strong pressure spikes or fracture clogging, and may include interactions via fracture networks as well. Indirect interactions may occur when the hydraulic stimulation-induced pressure wave propagates through the porous subsurface and reaches a nearby well with enough energy to cause damage. Damages can occur to downhole artificial lift equipment, through sand loading or pressure spikes, or manifest as production re-routing from one well to another or as production re-distribution within a well.
Fang, Zhi (Brunei Shell Petroleum Sdn Bhd) | Zamikhan, Norshah (Brunei Shell Petroleum Sdn Bhd) | Huver, Pieter (Brunei Shell Petroleum Sdn Bhd) | Ali, Waznah (Brunei Shell Petroleum Sdn Bhd) | Ahmadiah, Hanisah (Brunei Shell Petroleum Sdn Bhd)
Whilst drilling an exploration well through shallow depleted reservoirs, the heavily deviated intermediate hole section encountered uncontrollable losses, hole pack off, and ultimately was abandoned. A replacement sidetrack was proposed and the asset team requested an assessment of the drilling risks for the proposed trajectory. An integrated geomechanics approach was developed to analyze the fracture initiation pressures (FIP) of wellbores, which are dependent on well trajectories except on the field stresses and formation pressures. An FG model was elaborated with the integrated geomechanics approach analyzing the field data and the drilling history of the lost hole section. It predicted the FIPs of the initially proposed sidetrack trajectory with a value lower than the minimum required by the drilling team. The sidetrack trajectory was revised as instructed by the FG model analyses, which resulted in an increased FIP value slightly above the minimum required. The revised sidetrack trajectory observed minor losses with the ECD slightly exceeded the predicted FIP value during drilling, but the remaining section was successfully drilled by controlling the ECD under the predicted FIP value. If the primarily proposed sidetrack trajectory had been drilled, there could have been another lost-hole event due to the unmanageable drilling operation window. The integrated geomechanics approach eventually saved the challenging sidetrack through optimizing the trajectory by accurately predicting the FIPs.
Fang, Zhi (Brunei Shell Petroleum Co Sdn Bhd) | Zamikhan, Norshah (Brunei Shell Petroleum Co Sdn Bhd) | Tarang, Ravie-Tajit (Brunei Shell Petroleum Co Sdn Bhd) | On, Chee Khong (Brunei Shell Petroleum Co Sdn Bhd) | Huver, Pieter Hendricus (Brunei Shell Petroleum Co Sdn Bhd)
Fracture gradient (FG) of wellbores is the function of not only stresses, formation pressure and rock mechanical properties but also well trajectories. An accurate FG prediction is critical for safe well drilling. However, the existing methods do not account for the trajectory effects. An integrated geomechanical approach has been developed to more accurately predict the FG of wellbores subject to various trajectories. The approach deploys the Kirsch equations and takes into account the effects of formation pressure variations on stresses. It further integrates the elaborated individual procedures for deriving the geomechanical input parameters from regional field data to form a FG model. After verifying the losses test and offset well drilling data with necessary modifications, the calibrated FG model is then able to more accurately predict the fracture initiation pressure (FIP) of wellbores to mitigate the drilling losses for not only vertical but also deviated wellbores by guiding the equivalent circulation density (ECD) management.
The integrated geomechanical approach has been applied to the planning and drilling of more than 30 new wells at Brunei Shell Petroleum (BSP). It has significantly mitigated the drilling losses for the challenging wells of a field redevelopment project in which about 50 deviated wells were expecting narrow drilling windows due to penetrating heavily depleted reservoirs. In another drilling campaign, it saved the sidetrack of a lost hole section by revising the trajectory as instructed by the FIP predictions. The integrated geomechanical approach is an algorithm that can effectively mitigate drilling losses by accurately predicting the FG for any arbitrary wellbores.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Fang, Zhi (Brunei Shell Petroleum Co Sdn Bhd) | On, Chee Khong (Brunei Shell Petroleum Co Sdn Bhd) | Zamikhan, Norshah (Brunei Shell Petroleum Co Sdn Bhd) | Borah, Jahnabi (Brunei Shell Petroleum Co Sdn Bhd) | Spanninga, Christoffer (Brunei Shell Petroleum Co Sdn Bhd)
Lost circulation is one if the top concerns of drilling nearly 50 wells penetrating heavily depleted shallow reservoirs in a recent drilling campaign. Three of the first 5 wells observed losses with the fifth losing a hole section during drilling. A fracture gradient (FG) model developed by an integrated geomechanics approach assessed those five wells and indicated that the equivalent circulation density (ECD) was higher than the predicted FGs in the three losses wells but lower than the FGs in the two non-losses wells. The FG model guided the drilling team successfully re-drilled the lost section of the fifth well and accomplished another two wells by controlling the ECD under the predicted FGs. The sixth well had a predicted FG lower than the ECDs used in the fourth and fifth wells and could have encountered massive losses or losing a section again without the FG model. The FG model was further promoted to minimize the lost circulation risks by predicting the FG of additional 14 wells with 12 having been successfully drilled. It has saved about USD 500k per well on average with mitigating the lost circulation risks for those losses-prone wells by the integrated geomechanics approach. This approach is extended to assist managing the drilling safety and cost savings for remaining wells.
Recently, there has been a drive towards a risk-based approach to plug & abandonment (P&A) design. To apply a risk-based approach for decision-making, i.e. to decide if a P&A design is acceptable or not, risk acceptance criteria have to be established and be approved by authorities. This paper presents the core of a risk-based approach, and then present three alternative risk acceptance criteria based on leakage risk of permanently plugged and abandoned wells.
The core elements of the risk-based approach for evaluation of the containment performance in permanently plugged and abandoned wells consist of estimating probability of leakage and associated leakage rates for any proposed P&A design. These will then have to be used to evaluate the acceptability of the design, by comparing them to some defined acceptance criteria. Different principles can be followed to define such criteria, such as being consistent by accepting risk levels which have been considered acceptable in other situations, environmental survivability or considering the cost-benefit to optimize the allocation of funds.
The approach and principles used are described and applied in the context of P&A design. Based on the specification of an actual gas producing well that was permanently plugged and abandoned on the Norwegian Continental Shelf (NCS), a synthetic case study is established. Simulations are carried out to provide estimations of the core elements of the risk-based approach, i.e. leakage rate and probability of the leakage, for the synthetic case. Three examples of risk acceptance criteria are then presented and discussed. The estimations derived from simulations for the synthetic case study are used to exemplify the strengths and weaknesses of the three acceptance criteria.
Sorensen, James A. (Energy & Environmental Research Center) | Pekot, Lawrence J. (Energy & Environmental Research Center) | Rivero, Jose Torres (Energy & Environmental Research Center) | Jin, Lu (Energy & Environmental Research Center) | Hawthorne, Steven B. (Energy & Environmental Research Center) | Jacobson, Lonny (Energy & Environmental Research Center) | Doll, Tom (Energy & Environmental Research Center) | Smith, Steven (Energy & Environmental Research Center) | Flynn, Mary (XTO Energy Inc.)
In 2017, an injection test was conducted in a vertical well completed in the Middle Member of the Bakken Formation.
The first intelligent completion was deployed in the Snorre field offshore Norway in August 1997, marking a major milestone for advanced completion engineering, reservoir insight, and production control. For the first time, an operator could manipulate tubing outflow performance at, or near, the sandface inflow node, without intervention or workover, but rather live via remote control using an interval control valve (ICV). Twenty years later, technological advancements have significantly increased the reliability and capability of intelligent completion tools with applications in ultra-deepwater, mature fields, as well as in the cost-sensitive unconventional arena.
This paper discusses the significant technological advancements and reliability of ICVs by comparing the following: case history examples of technology, applications, and installations from the past and present; associated technological and operation challenges with solutions and resulting reliability increases; and a view of the future design and reliability aspects of ICVs with respect to hydraulic vs. electric control and actuation. ICV case history examples are discussed below:
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement. Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface. History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement. A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation. A Middle East operator's current application for low-cost ICVs. History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement.
Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface.
History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement.
A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation.
A Middle East operator's current application for low-cost ICVs.
History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
The steady increase in ICV reliability is the result of advancing technology, as well as continuous improvement in operational procedures. These case histories help detail each advancement.
The future of intelligent completions and ICVs is tied to precision of device control, system reliability assurance, and effective use of sensor data to generate recognizable value. Precision and data require electronic control and transmission; however, hydraulic actuation offers more advantages with current available technology. This paper concludes with an argument for the future of practical ICV installation, zone control, actuation, and closed-loop operator interface.
ABSTRACT: Solvent steam co-injection in oil sands reservoirs is generally understood to be superior to SAGD in terms of oil recovery rate, ultimate oil recovery and steam oil ratio. In solvent assisted SAGD (SA-SAGD), the combination of temperature distribution and solvent concentration profiles ahead of the steam chamber edge reduces the virgin bitumen viscosity and therefore has major control over oil drainage rate in the mobile zone. Recent coupled reservoir-geomechanical simulation results from Abbasi Asl and Chalaturnyk (2016) revealed that these profiles could be significantly influenced by the shear dilation/volume change that is induced around the chamber edge. A complete understanding of the interplay between solvent transport, heat transfer, solvent-oil phase behavior and shear induced volume change and associated sensitivities requires an analytical study which is currently lacking in the literature.
This research presents the result of a semi-analytical study to examine the conditions under which the induced volume change beyond the steam chamber edge could impact SA-SAGD performance and process design such as: optimum solvent selection and required injection volumes. Simplifications had to be made in order to allow us to solve the complex interaction of energy, mass transfer and rock property alterations around the steam chamber edge, while preserving the fundamental physics.
Single component solvent co-injection cases were considered and the corresponding phase behavior calculations were performed to yield solvent concentration and temperature at the steam chamber edge. Assuming 1-D heat conduction and pressure diffusion perpendicular to the interface, stress and volume changes were calculated beyond the chamber edge. The resulting enhancements in compressibility and effective permeability were consequently utilized to account for the heat convection and solvent dispersion, generating the ultimate temperature and solvent concentration profiles. Darcy’s law and mass balance were eventually applied to derive oil drainage rate. Sensitivity analyses were performed on injection pressure and solvent molar concentrations at the edge.
The semi-analytical modeling results demonstrated case studies where Geomechanically induced volume changes improved effective permeability, convective heat transfer and solvent dispersion inside the mobile zone. Consequently, oil drainage rate was improved and it was found out that optimum injection scenarios shifted towards solvents with reduced concentrations. It was also shown that geomechanical processes favor heavier solvents. These findings have significant implications with regards to the economy of the process. This modeling approach provides us with an inexpensive tool to identify the reservoir and operational conditions where SA-SAGD performance could be heavily influenced by Geomechanics.
Later, after a similar amount of time, the hydrofracture arrived at the original Middle Bakken producer well, indicated by the onset of increasing pressure recorded by the gauge in that well. Looking at the profile view of events from H2 Stage 1, we see that the fracture starts in the Middle Bakken and grows downward to include the Three Forks, obtaining its maximum height fairly early, and then advances asymmetrically toward the depleted area surrounding the H1 (Figure 1). The easternmost well (H2) was fractured first. As shown in Figure 1, the pressure gauge in the H1 well exhibits a pressure increase for each fracture stage in the H2 well, for which the primary fracture azimuth encounters the depleted well (i.e., Stages 1 through 14). Fractures created during subsequent stages pass below the bend of the H1 well and are not registered on the pressure gauge. The orientation of H2 causes these final fracture stages to share a common trajectory, which trends in the direction of the maximum horizontal stress over this portion of the well. These fractures combined and propagated longer distances; however, no associated pressure fluctuations were recorded because they pass below the H1 well.