Anderson, Iain (Heriot-Watt University) | Ma, Jingsheng (Heriot-Watt University) | Wu, Xiaoyang (British Geological Survey) | Stow, Dorrik (Heriot-Watt University) | Underhill, John R. (Heriot-Watt University)
This work forms part of a study addressing the multi-scale heterogeneous and anisotropic rock properties of the Lower Carboniferous (Mississippian) Bowland Shale; the UK's most prospective shale-gas play. The specific focus of this work is to determine the geomechanical variability within the Preese Hall exploration well and, following a consideration of structural features in the basin, to consider the optimal position of productive zones for hydraulic fracturing. Positioning long-reach horizontal wells is key to the economic extraction of gas, but their placement requires an accurate understanding of the local geology, stress regime and structure. This is of importance in the case of the Bowland Shale because of several syn- and post-depositional tectonic events that have resulted in multi-scale and anisotropic variations in rock properties. Seismic, well and core data from the UK's first dedicated shale-gas exploration programme in northwest England have all been utilized for this study. Our workflow involves; (1) summarizing the structural elements of the Bowland Basin and framing the challenges these may pose to shale-gas drilling; (2) making mineralogical and textural-based observations using cores and wireline logs to generate mineralogy logs and then to calculate a mineral-based brittleness index along the well; (3) developing a geomechanical model using slowness logs to determine the breakdown stress along the well; (4) placing horizontal wells guided by the mineral-based brittleness index and breakdown stress. Our interpretations demonstrate that the study area is affected by the buried extension of the Ribblesdale Fold Belt that causes structural complexity that may restrict whether long-reaching horizontal wells can be confidently drilled. However, given the thickness of the Bowland Shale, a strategy of production by multiple, stacked lateral wells has been proposed. The mineralogical and geomechanical modelling presented herein suggests that several sites retain favorable properties for hydraulic fracturing. Two landing zones within the Upper Bowland Shale alone are suggested based on this work, but further investigation is required to assess the impact of small-scale elastic property variations in the shale to assess potential for well interference and optimizing well placement.
The Bowland Shale is a Carboniferous formation of Asbian to Yeadonian age located in Northern England. It is estimated to have a shale gas section with more than 5,000 ft thickness holding over 1300 TCF of total original gas in place. Drilling in the Bowland Basin started in August 2010 and by the end of 2011, three vertical wells (PH-1, GH-1 and BS-1) were drilled to a depth of 8,860 to 10,500 ft with objective of logging and coring the potential shale gas formations including Upper Bowland, Lower Bowland, Hodder Mudstone and Sabden Shale. All the drilled wells encountered several borehole stability problems, such as tight-hole, pack-off, overpull and excessive cutting, causing significant non-productive time (NPT) during drilling. Specifically, in GH-1 and BS-1, side-tracking was required to reach the target depth which imposed significant cost to the project. Careful investigation of the recorded drilling problems showed that majority of them were associated with formation collapse due to insufficient drilling fluid pressure. Fluid losses also occurred in some of the formations due to either too high of downhole pressure or presence of critically stressed natural fractures. These incidents implied that the applied casing design and mud weight program were not appropriate for the current-day state of stress and rock properties.
A comprehensive experimental and analytical geomechanical study was carried out to develop a reliable borehole stability model that can firstly explain the observed drilling incidents and secondly provide guidance for design and drilling of the planned wells. The plan was to drill a S-shape appraisal well (PNR-1) in the Preston New Road exploration site to log and core the Bowland Shale sequence and select the optimum landing depths for subsequent horizontal sections (PNR-1z and PNR2) to be completed for multi-stage hydraulic fracturing. The study recognized intrinsic shale anisotropy as a primary causative factor for borehole stability issues and formation collapses in the offset wells. Other important factors were identified to be the abnormal pore pressure regime and the presence of a tectonic strike-slip stress regime with large horizontal stress anisotropy. The anisotropy of the Bowland Shale was characterized in both laboratory and field scales, and anisotropic wellbore stability models were developed for offset and planned wells. As a result of this study, the PNR-1, PNR-1z and PNR2 wells were successfully drilled and completed with no notable borehole stability problems despite the presence of narrow operating mud weight window in several stratigraphic intervals. This paper presents a summary of the conducted borehole stability analysis aiming at risk-free and successful drilling of horizontal wells in the Preston New Road exploration site with emphasis on the effect of shale anisotropy.
Makwashi, Nura (Division of Chemical and Petroleum Engineering, London South Bank University) | Sarkodie, Kwame (Division of Chemical and Petroleum Engineering, London South Bank University) | Akubo, Stephen (Division of Chemical and Petroleum Engineering, London South Bank University) | Zhao, Donglin (Division of Chemical and Petroleum Engineering, London South Bank University) | Diaz, Pedro (Division of Chemical and Petroleum Engineering, London South Bank University)
Curved pipes are essential components of subsea process equipment and some part of production pipeline and riser. So far, most of the studies on of wax deposition and the possible mitigation strategies have been carried out using straight pipelines, with little attention given to curved pipes. Therefore, the objective of this study is to use an experimental flow loop designed and assembled in the lab to study and understand the mechanisms and variable parameters that affect wax depositional behaviour under the single-phase flow. Series of experiments were carried out with pipes curvatures of 0, 45 and 90-degree at different flow rates (2 and 11 L/min). The sequence in which the bends are incorporated creates non-uniformity of boundary shear, flow separation, and caused isolation of fluid around the bends that affect wax deposition, which depends on flow regimes – Reynolds number along with the radius of curvature of the bend. Prior to the flow loop experiment, the waxy crude oil was characterized by measuring the viscosity, WAT (30°C), pour point (25.5°C), n-Paraffin distribution (C10 - C67), and the saturated/aromatic/resin/asphalte (SARA) fractions
Results of this study shows that the wax deposit thickness decreases at higher flow rate within the laminar (Re<2300) and turbulent (Re>2300) flow regimes. It was observed that the deposition rate was significantly higher in curved pipes, about 8 and 10% for 45 and 90-degree, respectively in comparison to the straight pipe for all flow conditions. Increase elevation of the curved pipe, however, led to a more wax deposition trend; where a higher percentage of wax deposit was observed in 45-degree compared to 90-degree curved pipe. This trend was due addition of gravity forces to the frictional forces - influenced by the physical mechanisms of wax deposition mainly molecular diffusion, shear dispersion and gravity settling. From the results of this study, a new correlation between wax deposit thickness and pressure drop was developed. A relationship was established between wax deposit thicknesses, bend angle in pipes and wax deposition mechanisms with a reasonable agreement with published data, especially for steady state condition. Therefore, this study will enhance the understanding of the wax deposition management and improve predictions for further development of a robust mitigation strategy.
The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir.
Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other.
The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments.
It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing.
Therefore the use of AICDs is a real option for horizontal well completion.
This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.
Nandi Formentin, Helena (Durham University and University of Campinas) | Vernon, Ian (Durham University) | Avansi, Guilherme Daniel (University of Campinas) | Caiado, Camila (Durham University) | Maschio, Célio (University of Campinas) | Goldstein, Michael (Durham University) | Schiozer, Denis José (University of Campinas)
Reservoir simulation models incorporate physical laws and reservoir characteristics. They represent our understanding of sub-surface structures based on the available information. Emulators are statistical representations of simulation models, offering fast evaluations of a sufficiently large number of reservoir scenarios, to enable a full uncertainty analysis. Bayesian History Matching (BHM) aims to find the range of reservoir scenarios that are consistent with the historical data, in order to provide comprehensive evaluation of reservoir performance and consistent, unbiased predictions incorporating realistic levels of uncertainty, required for full asset management. We describe a systematic approach for uncertainty quantification that combines reservoir simulation and emulation techniques within a coherent Bayesian framework for uncertainty quantification.
Our systematic procedure is an alternative and more rigorous tool for reservoir studies dealing with probabilistic uncertainty reduction. It comprises the design of sets of simulation scenarios to facilitate the construction of emulators, capable of accurately mimicking the simulator with known levels of uncertainty. Emulators can be used to accelerate the steps requiring large numbers of evaluations of the input space in order to be valid from a statistical perspective. Via implausibility measures, we compare emulated outputs with historical data incorporating major process uncertainties. Then, we iteratively identify regions of input parameter space unlikely to provide acceptable matches, performing more runs and reconstructing more accurate emulators at each wave, an approach that benefits from several efficiency improvements. We provide a workflow covering each stage of this procedure.
The procedure was applied to reduce uncertainty in a complex reservoir case study with 25 injection and production wells. The case study contains 26 uncertain attributes representing petrophysical, rock-fluid and fluid properties. We selected phases of evaluation considering specific events during the reservoir management, improving the efficiency of simulation resources use. We identified and addressed data patterns untracked in previous studies: simulator targets,
We advance the applicability of Bayesian History Matching for reservoir studies with four deliveries: (a) a general workflow for systematic BHM, (b) the use of phases to progressively evaluate the historical data; and (c) the integration of two-class emulators in the BHM formulation. Finally, we demonstrate the internal discrepancy as a source of error in the reservoir model.
The Bowland Basin in Northern England contains a thick shale gas section (>5,000 ft) estimated to hold over 1300 TCF of total original gas in place of shale gas resource. In 2017, Cuadrilla Resources drilled a S-shaped pilot well, Preston New Road-1 (PNR-1), located in Lancashire, NW England. The plan was to drill, core, and log the Bowland Shale sequence with the primary objective to select the optimum landing depth for a subsequent side-tracked horizontal section (PNR-1z) of up to 3,280 ft length to be completed for multi-stage hydraulic fracturing. Another multi-stage horizontal well, PNR2, was also planned to be drilled afterward targeting a different stratigraphic horizon. Three vertical wells (PH-1, GH-1 and BS-1) were previously drilled in the Bowland Basin to a depth of 8,860-10,500 ft. Delays were encountered in the drilling of these wells due to multiple borehole stability problems. Specifically, in GH-1, the well required a side-track to reach the target depth. With the plan to drill four horizontal wells at Preston New Road, the first horizontal wells ever to be drilling in the Bowland shale, a rigorous geomechanical study was required to provide valuable insights for optimisation of the drilling programme.
A pre-drill geomechanical model was developed for the PNR-1 pilot well using advanced interpretation of available data and the gained experiences from the offset wells. A comprehensive pore pressure interpretation showed that Bowland shale is significantly over-pressured (0.69 psi/ft). The model was backed up by the observed splintery cuttings and gas shows in offset wells. It was concluded that this abnormal pore pressure combined with a tectonic strike-slip stress regime (with large horizontal stress anisotropy) and intrinsic anisotropic shale properties were the primary causative factors for drilling incidents. As a result of this study, the PNR-1 was successfully drilled and completed with minimal borehole stability problems despite the presence of narrow operating mud weight window in several stratigraphic intervals. The data acquisition program conducted included 114m of core from Upper and Lower Bowland shales, with the required logs for updating the geomechanical model. A comprehensive rock mechanics testing program was designed and conducted which resulted in better characterizing the anisotropic elastic properties and strength parameters of the Bowland Shale. This information was used to update the geomechanical model and aid the optimum landing decision depth of 2,180m for PNR-1z. A successful XLOT prior to drilling the 6" lateral section provided valuable data for further calibration of the stress model. The updated model was then used to develop safe operating mud weight window for PNR-1z, which helped drilling of the horizontal section to the TD at 11,233 ft MD (7,457 ft TVD) with no notable drilling problems.
This paper presents a summary of the geomechanical work performed for successful drilling and hydraulic fracturing operations in the Preston New Road exploration site and the outcomes and achievements.
Relative permeability (kr) functions are among the essential data required for the simulation of multiphase flow in hydrocarbon reservoirs. These functions can be measured in the laboratory using different techniques including the steady state displacement technique. However, relative permeability measurement of shale rocks is extremely difficult mainly because of the low/ultralow matrix permeability and porosity, dominant capillary pressure and stress-dependent permeability of these formations.
In this study, the impacts of stress and capillary end effects (CEE) on the measured relative permeability data were investigated. The steady state relative permeability (SS-kr) measurements were performed on Eagle Ford and Pierre shale samples. To overcome the difficulties regarding the kr measurements of shale rocks, a special setup equipped with a high-pressure visual separator (with an accuracy of 0.07 cc) was used. The kr data were measured at different total injection rates and liquid gas ratios (LGR). In addition, to evaluate the impacts of effective stress, the kr data of an Eagle Ford shale sample were measured at two different effective stresses of 1000 and 3000 psi.
From the experimental data, it was observed that the measured SS-kr data of the shale samples have been influenced by the capillary end effects as the data showed significant variation when measured at different injection rates (with the same LGR). This suggested that the liquid hold-up (i.e. capillary end effects) depends on the competition of capillary and viscous forces. In addition, it was shown that it is more necessary to correct the experimental kr data measured at the lower LGRs. Furthermore, different relative permeability curves were obtained when the kr data were measured at different effective stresses. This behavior was explained as the capillary pressure was expected to be more dominant at the higher effective stress.
The results from this study improve our understanding of unconventional mechanisms in shale reservoirs. It is evident that the behavior of unconventional reservoirs can be better predicted when more reliable and accurate relative permeability data are available. The outcomes of this study will be useful for accurate determination of such kr data.
The major accident of 6 July 1988, when Britain’s Piper Alpha facility caught fire and exploded, remains one of the worst imaginable scenarios for everyone working in and with the petroleum industry. Its lessons are still relevant. The Piper Alpha incident in the UK North Sea had a profound impact on the development of process safety culture and legislation around the world. With the great crew change already taking place, this column reflects on the disaster to ensure that its lessons are not forgotten.
The outlook in the UK is a case study of the squeeze facing E&P in other basins where operators are trying to pay to sustain production with discoveries, while plugging and abandoning old wells, all paid for by the lean cash flow due to low oil prices. Subsea inspection/repair/maintenance services have traditionally relied on vessel-based, ROV, or diver operations. In the longer term, identifying significant incremental savings in these operations is not sustainable and an innovative approach deploying digital technologies is being investigated. The deal gives Equinor an additional 7.5% ownership stake in the Njord redevelopment project and associated tiebacks in the Norwegian Sea, and potentially raises Faroe’s value in the midst of a hostile takeover attempt by DNO. Startup comes 8 months after the initial discovery in March, marking the second successful tieback since 2017 to the Beryl Alpha platform in the UK North Sea.
Researchers at Heriot-Watt University in Edinburgh, Scotland, are building replica core samples using 3D printers and installing sensors inside them as they go. Their goal is to directly monitor pore-scale flow behavior from the inside of these so-called “smart rocks.” Service companies are using the latest generation of additive manufacturing technology to print out steel components for big ticket downhole tools. There is great potential for the technology to drive down equipment costs and improve performance.