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Abstract The gas present in the Valhall overburden crest area interferes with the seismic data and obscures the fault detection (minor faults). Spatially resolving fractures and fracture network is essential for subsurface understanding and future well placement in this field, and it is a critical input to the dynamic reservoir model. Additionally, mapping the fracture network in poor permeable reservoir formation beyond the wellbore is crucial to identify completion intervals to maximize productivity/injectivity, and hence field value. The well 2/8-F-18 A was drilled on the crest of the Valhall field as a pilot water injector in Lower Hod formation, where core and data analysis formed the foundation for a future potential 11 well development. The well is placed in the southern section of the Valhall crest, and no major faults or strong amplitude features were mapped out in the overburden via surface seismic before drilling. In this case study, an integrated workflow is proposed and tested within the reservoir formation to identify “sweet” (permeable and fractured) zones beyond the wellbore. This is achieved using borehole acoustic data combined with image and ultrasonic imaging to characterize fracture networks beyond the borehole wall. The sonic imaging workflow identifies reflection events from fractures and faults and provides the true dip, azimuth, and location in 3-dimensions. This data is complemented by nuclear magnetic resonance (NMR), dielectric and spectroscopy data to understand reservoir petrophysics. NMR-derived permeability has also been evaluated for identifying high permeable zone in this formation, which primarily focuses on intergranular permeability of the formation a few inches away from the borehole wall. Reservoir textural heterogeneity and fractures beyond the wellbore wall make this method difficult to estimate or enhance the effective permeability estimate. The baseline assumption for the NMR permeability estimation is also not valid in Hod formation; the Timur and SDR equation needs significant change to match core permeability. Hence, the primary aim is to identify a fracture network that will help support water injection and maximize hydrocarbons production through them. The goal is to establish a workflow from the learnings of this study, performed on the pilot well, validate its findings with the near-field data (core, imaging, and ultrasonic), and optimize it if needed (described in the methodology section). The developed workflow is then intended to be used to optimize the placement of future wells. The results achieved from the integrated workflow identified a key fault and mapped it approximately 23 meters away on each side of the borehole. It also captures acoustic anomalies (high amplitudes), validated based on near-field data, resulting from a fracture network potentially filled with hydrocarbons. The final results show the sub-seismic resolution of the fracture and fault network not visible on surface seismic due to the gas cloud above the reservoir and frequency effect on the surface seismic when compared to borehole sonic data. Evidently enhancing the blurred surface image, which helps enhance the structural and dynamic model of the reservoir.
Volkov, Maxim (TGT Oil and Gas Services) | Björk, Henric (Equinor) | Kudriavaia, Natalia (TGT Oil and Gas Services) | Andrews, Jamie Stuart (Equinor) | Carlsen, Truls (Equinor) | Strøm, Steinar (Equinor)
Abstract The Extended Leak Off Test (XLOT) is a sophisticated formation integrity test that can be performed during drilling, recompletion, or at the well abandonment stage. The test is usually characterized by multiple cycles, creating and manipulating a fracture that can extend several meters away from the wellbore. The test can provide more data (both formation stress and fracture mechanics) compared to traditional leak-off tests. This data is used extensively both for determination of the in-situ formation stress for well barrier integrity assessment and for more general rock mechanical work such as quantifying fracture gradient for use in wellbore stability programs for drilling and completion operations. The interpretation is performed by analysis of the surface pressure and, often with downhole data from memory gauges (or, increasingly, with real-time data from wired pipe) at different stages of the XLOT test. The typical XLOT pressure analysis chart is shown below (see Fig.1). The key determined parameters are:–Leak Off Pressure (LOP) –Fracture Initiation Pressure (FIP) –Formation Break Down Pressure (FBR) –Formation Propagation Pressure (FPP) –Instantaneous Shut-In Pressure (ISIP) –Formation Closure Pressure (FCP) –Fracture Reopening Pressure (FRP) Figure 1: The traditional XLOT interpretation plot. A key requirement of the test is to ensure hydraulic connectivity to the targeted formation only. This can be achieved in the case where annulus barriers are in place and perform well. Unintentional communication to non-targeted zones may result in abnormal behavior, more complex interpretation of obtained data, larger uncertainty in the meaning of the results and ultimately failure of the XLOT test. To verify the well barriers integrity prior to the XLOT different techniques can be utilized. The main one is cement bond logging across the cemented barriers. This indicates the condition of the cement behind the first casing and increases the level of confidence the test will be conducted successfully. "However, recent case studies have shown that an indication of good bond above and/or below the target formation from a cement bond log cannot guarantee the isolation required to sufficiently hold the applied pressure [Maxim Volkov]." The paper demonstrates an approach taken by Equinor in a special application where XLOT testing was advanced by adding downhole monitoring during the test. This targeted the following parameters to evaluate the new essential components of XLOT interpretation: –depth and capacity of opened and re-opened fractures, –actual sealing of the cement barriers above and below the targeted zone, –failure investigation in case the FBP cannot be achieved.
This paper reviews two newly developed novel completion systems that significantly reduce time spent performing multistage stimulation in environments where cost and consequence of failure are high. Both coiled-tubing and wireline-manipulated sliding-sleeve/valve systems and ball-drop-actuated systems have been developed and deployed, depending on the various completion and stimulation challenges faced. Since their first installation in 2009, these systems have been proven and refined in multiple wells for two major operators. For many of the fields requiring stimulation in the North Sea, cemented plug-and-perforation (plug-and-perf) completions have been used historically. It is a flexible solution in terms of the various types of stimulation designs that can be accommodated.
Waste injection in shale, with matrix permeability in the nanodarcy range and without the presence of any permeable layers, has been performed on the Norwegian Continental Shelf (NCS) for more than 15 years. To avoid leakages to the seafloor using this method, techniques have been developed that allow wells to dispose of several million barrels into individual shale domains, with vertical propagation of the disposal domain less than 1,000 ft above the injection point. Recently, use of frequent 4D interpretations of seismic surveys shot over a permanent sensor array allowed detailed domain mapping and independent dynamic monitoring. Changes of North Sea regulations in the mid- to late 1990s made the seabed disposal of oily cuttings and other waste from drilling and production impossible without the use of significant topside cleaning systems. Meanwhile, the development of fields required increasingly complex wells, resulting in the almost systematic use of oil-based mud for efficient drilling.
To the casual observer of completions and hydraulic fracturing, it might appear that multifractured horizontal wells are a relatively recent concept that materialized just as we required them for unconventionals. However, those in the know will recognize that the marriage of fracturing and stimulation operations with horizontals was forged almost 30 years ago in an environment far removed from unconventionals. In fact, it was the high-cost, limited-well, offshore environment that drove the need for higher production rates from single wellbores and indeed from horizontals and high-angle wells because of the limitations imposed by platform footprint and achievable step-out geometry. Substantial progress in multifractured horizontal wells was made in the 1990s by operators such as Maersk on the Dan field and BP on the Valhall field, in addition to onshore experiences with various operators such as UPRC in the Austin chalk and Arco in Alaska (the North Slope operational reality being effectively similar to offshore). Therefore, it is with great satisfaction that this month's technical section includes papers demonstrating technologies from unconventionals that are beginning to be used to develop these offshore opportunities further.
Summary Knowledge of fracture‐entry pressures or formation‐face pressures (FFPs) during acid‐fracturing treatments in real‐time mode can help in evaluating the effectiveness of the treatment and improve the decision‐making process during execution. In this paper, methods and tools used to generate FFPs in real‐time mode with the help of bottomhole‐pressure (BHP) data are discussed in detail. The horizontal wells selected for the study were drilled and completed in the North Sea with permanent BHP gauges that enabled constant monitoring of downhole pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, fluid type, wellbore details, and wellbore deviation, along with bottomhole‐gauge pressures, to calculate fracture‐inlet pressures just outside the casing at active perforation(s) depth. The tool performs the calculations in “live” mode during treatment execution and simultaneously generates a dynamic array of data that assists in “on‐the‐fly” evaluation and the decision‐making process. Several acid‐fracture treatments were analyzed using the tool and led to important conclusions related to fracture‐propagation modes, acid‐exposure times, and the effectiveness of given acid types. The results had a direct influence on the modification of treatment designs and pump schedules to optimize treatment outcomes.
Buijs, Hernán (Wintershall Dea Headquarters) | Guerra, Clairet (Wintershall Dea Headquarters) | Sonwa, Roger (Wintershall Dea Headquarters) | Nami, Patrick (Wintershall Dea Headquarters) | Vecchia, Luciano (Wintershall Noordzee B.V) | Ishmuratov, Roman (Wintershall Noordzee B.V)
Hydraulic fracture design driven by multi-disciplinary collaboration can maximize the production potential of complex multi-frac horizontal wells. Integration of multiple information sources (i.e.: geological, dynamic and geomechanical data) allows to build representative models and have proven to improve modelling towards a realistic understanding of tight reservoir performance of several multi-fracced wells. 3D properties encompassing the reservoir geological heterogeneity, pore pressure, mechanical elasticity and state of stress were utilized to develop a strategy to fracture stimulate a horizontal wellbore in the North Sea Region. The study was instrumental to build fit-for-purpose hydraulic fracture designs by incorporating state of stress changes related to pore pressure depletion on different faulted compartments supported by a reservoir dynamic simulation. Such models provided meaningful value to optimize the well trajectory used to access the host rock, understand fracture height growth possibilities in different compartments and define the number/size of hydraulic fractures required for optimum production.
Kallesten, Emanuela (University of Stavanger, Norway) | Andersen, Pål Østebø (University of Stavanger, Norway) | Berawala, Dhruvit Satishchandra (University of Stavanger, Norway) | Korsnes, Reidar Inge (University of Stavanger, Norway) | Madland, Merete Vadla (University of Stavanger, Norway) | Omdal, Edvard (ConocoPhillips, Norway) | Zimmermann, Udo (University of Stavanger, Norway)
Summary Understanding the effect of typical water‐related improved oil recovery techniques is fundamental to the development of chalk reservoirs on the Norwegian Continental Shelf (NCS). We investigate the contribution and interplay of key parameters influencing the reservoir's flow and storativity properties, such as effective stresses, injecting fluid chemistry, and geomechanical deformation. This is done by developing a mathematical model that is applied to systematically interpret experimental data. The gained understanding is useful for improved prediction of permeability development during field life. The model we present is for a fractured chalk core whereby fluids can flow through the matrix and fracture domains in parallel. The core is subject to a constant effective stress above the yield, resulting in time‐dependent compaction (creep) of the matrix, while the fracture does not compact. Reactive brine injection causes enhanced compaction but also permeability alteration. This again causes a redistribution of injected flow between the two domains. A previous version of the model parameterizing the relation between chemistry and compaction is here extended to quantify the effect on permeability and see the effect of flow in a fracture‐matrix geometry. A vast set of experimental data were used to quantify the relations in the model and demonstrate its usefulness to interpret experimental data. Two outcrop chalk types (Aalborg and Liège) being tested at 130°C and various concentrations of Ca‐Mg‐Na‐Cl brines are considered. However, assumptions were required, especially regarding the fracture behavior because directly representative data were not available. The tests with inert injecting brine were used to quantify the effect of matrix and fracture mechanical compaction on permeability trends. To be able to explain the tests with reactive brine, an important finding is that permeability not only decreased because of enhanced porosity reduction but also because of a quantifiable chemistry‐related process (dissolution/precipitation). Sensitivity analyses were performed regarding varying fracture width, injection rate, and chemistry concentration to evaluate the effect on chemical creep compaction and permeability evolution in fractured cores. The model can be used to highlight parameters with great influence on the experimental results. An accurate quantification of such parameters will contribute to refining laboratory experiments and will provide valuable data for upscaling and field application.
Lubbad, Raed (Arctic Integrated Solutions (ArcISo AS) / Sustainable Arctic Marine and Coastal Technology (SAMCoT), Centre for Research-based Innovation (CRI), Norwegian University of Science and Technology (NTNU)) | Lu, Wenjun (Arctic Integrated Solutions (ArcISo AS) / Sustainable Arctic Marine and Coastal Technology (SAMCoT), Centre for Research-based Innovation (CRI), Norwegian University of Science and Technology (NTNU)) | van den Berg, Marnix (Arctic Integrated Solutions (ArcISo AS) / Sustainable Arctic Marine and Coastal Technology (SAMCoT), Centre for Research-based Innovation (CRI), Norwegian University of Science and Technology (NTNU)) | Løset, Sveinung (Arctic Integrated Solutions (ArcISo AS) / Sustainable Arctic Marine and Coastal Technology (SAMCoT), Centre for Research-based Innovation (CRI), Norwegian University of Science and Technology (NTNU)) | Tsarau, Andrei (Arctic Integrated Solutions (ArcISo AS))
ABSTRACT Arctic business is developing within the sectors of marine operations related to offshore oil and gas, mining, seafood, tourism, scientific expeditions, and world trade shipping. As offshore activities in the Arctic is a relatively new field, with only a handful relevant operations to draw experience from, and since full-scale trials are extremely expensive, there is an expressed need for more detailed and cost-efficient analysis and design review of concepts based on numerical simulations. Over the years, various numerical simulators, with different levels of technical readiness, have been developed to address issues related to Arctic Offshore Engineering. This paper focuses on the development of the Simulator for Arctic Marine Structures (SAMS), its basic theories and recent engineering applications. These include structural damage assessment for simulating the impact between a wave driven glacial ice feature with a semi-submersible structure; the decision-making support by ice load calculations on a shipwreck in the Arctic; and various Arctic vessel navigation simulations. The technical advancement in terms of multi-body dynamics, ice fracture mechanics and hydrodynamics that the simulator is built on is manifested. The presented engineering applications signify the importance, the versatility and maturity of SAMS in dealing with complex ice – structure interaction issues at different scales and at various levels of complexities. INTRODUCTION For Arctic structural design and most Arctic operation planning, ice load calculations are one of the key components. However, ice load calculation is complicated by various ice conditions and different ice failure modes. As Palmer et al. (1983) stated, ‘it is no more likely that there should be a universal ice-force formula than that there should be a universal formula for the force on a body in a moving fluid, and in the present state of knowledge, it would be unwise to expect too much’. Over the years, the common engineering practice, e.g., (ISO19906, 2019), in calculating ice load on a given structure takes several steps of presumptions: an assumption on the limiting mechanism and an assumption on the various possible failure modes (Løset et al., 2006, Sanderson, 1988, Palmer and Croasdale, 2013). These approaches often offer one design value and are handy for fast calculations, however, require high engineering experience in making sound judgements. As time steps into the new century, our computational power and tools are getting more advanced. In addition, our understanding towards the mechanics of ice – structure interactions are also ever growing thanks to more accumulated data and theoretical advancement. It is now at our disposal to 1) get rid of all those initially needed interaction scenario presumptions and start from the beginning with given ice condition and structure 2) to obtain time domain analysis of both the ice action and its effect on the structure; 3) in addition, these calculations can be so fast that an almost real-time domain analysis becomes possible, which opens door for simulations of Arctic marine operation. Given the background and targets, the Simulator for Arctic Marine Structures (SAMS) is developed over the past 8 years. This paper documents the theoretical background of SAMS and its recent applications.
A significant component of progress in engineering is through failure. The focus of this paper is on ship and offshore structures although the observations are applicable to other engineering disciplines. There are many categories of sources of failure. The primary interest here is how the industry responds to broad and discrete technological changes that impact how ship and offshore structures are designed. Several examples of failures are described together with the shortcomings that led up to them. The lessons learned are synthesized in an effort to draw broad conclusions. The paper closes with recommendations on how the industry can improve its approach to dealing with change.