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Carlsen, Mathias (Whitson) | Whitson, Curtis (Whitson) | Dahouk, Mohamad Majzoub (Whitson) | Younus, Bilal (Whitson) | Yusra, Ilina (Whitson) | Kerr, Erich (EP Energy) | Nohavitza, Jack (EP Energy) | Thuesen, Matthew (EP Energy) | Drozd, John (EP Energy) | Ambrose, Ray (EP Energy) | Mydland, Stian (NTNU)
The objective of this paper is to help understand the mechanisms behind gas-based enhanced oil recovery (EOR) seen in actual field performance. This is accomplished by computing and interpreting daily wellstream compositions obtained from production data during the production period(s) of Huff-n-Puff (HnP) wells in the Eagle Ford, together with relevant PVT and numerical modeling studies.
Wellstream compositions are determined from readily available production data using an equation of state (EOS) model and measured oil and gas properties obtained from sampling at the wellhead. The wellstream composition is estimated daily in one of the following two ways: (1) if measured properties from field sampling are available, then regress to find a wellstream composition that matches all the measured oil and gas properties (e.g. stock-tank oil API, gas specific gravity, GOR, and separator fluid compositions). (2) if no measured properties from field sampling are available, then flash the most-recent wellstream composition estimated from (1) and recombine the resulting oil and gas streams to match the producing GOR.
Multiple lab-scale HnP EOR experiments and associated results have been published earlier, but only limited amounts of compositional data have been presented. In this study, we attempt to link produced wellstream compositions with simulated laboratory compositions reflecting different EOR recovery mechanisms. These results should enhance the understanding of the HnP EOR mechanisms to further optimize injection and production strategies, ultimately leading to higher recoveries. The data and observations from this analysis are presented in detail. The wellstream compositions before and after HnP implementation are shown and interpreted.
By providing daily estimates of oil and gas compositions, the compositional tracking technology presented in this paper can be used as a tool to understand key mechanisms behind the reported uplift seen in EOR in unconventional resources. The identification of these mechanisms is important for companies that are implementing EOR, because it allows them to optimize their EOR strategies, target higher recoveries, and increase the technical certainty in reserve booking.
ABSTRACT: Experience from North Sea wells shows that shale may be able to form sealing barriers around cased boreholes. Laboratory experiments with hollow cylindrical shale cores with a centralized tube in the borehole demonstrate the same phenomenon. These tests identify under which conditions and with what kind of shales barriers are formed. The focus of the present study is shale characterization, primarily through consolidated undrained (CU) triaxial tests, to assess attributes of barrier forming shales and to better understand the mechanisms. The pore pressure evolution in these tests seem to play a key role in deciding to what extent shale fails in a ductile manner, leading to sealing shale barriers, or in a more brittle manner, where possibly formed barriers are not sealing. In the analysis, Skempton parameters have been determined at different stages in the tests, demonstrating how the failure mode can be driven by the pore pressure changes. Soil mechanics concepts of normally consolidated vs overconsolidated behavior are valid for distinguishing between brittle and ductile shales.
The way rock failure occurs has significant practical importance: Fracture initiation and propagation, borehole collapse during drilling, and the formation of natural barriers around wells are all examples of processes that are strongly influenced by pre- and post-failure behavior. Operational decisions are often based on whether these processes are brittle or ductile, without having a firm scientific basis for what is “brittle” and what is “ductile”.
The work presented here is focused on the formation of shale barriers around cased wells: Field observations from the North Sea (Williams et al., 2009, Kristiansen et al., 2018) show wells where the annulus behind the casing has been closed by surrounding shale formations. This may occur a short time after drilling or may evolve over periods of months or years. Intuitively, shale barriers are associated with ductile behavior, involving mechanisms such as creep and plastic deformation. Since shales in their natural environment have permeabilities in the nanoDarcy range, one expects excellent seal efficiency, and shale barriers are therefore attractive for plugging and abandonment of old wells and may be considered as an alternative to cement for new wells. In both cases, there is a need to identify possibly barrier forming shales in advance, based on knowledge of petrophysical characteristics as well as mechanical behavior that may be assessed from core measurements in the laboratory, which are occasionally used to predict borehole instabilities during drilling. Also, observed instabilities like hole collapse may be used as guidelines for selecting barrier forming formations, in particular if the failure mode is recognized as ductile flow of the formation rather than localized breakouts.
In anisotropic materials Skempton's B parameter becomes a second order tensor. It is well established from laboratory experiments that the Skempton B tensor may deviate significantly from isotropy, which will influence the pore pressure response. The anisotropy of B in essence results from the anisotropy of the rock formation, and as a result the effects of the tensor Skempton cannot be considered without taking the underlying anisotropy into account. In this paper we use an implementation of Amadei's (1983) solution of the stress field around the borehole in an anisotropic formation to study the Skempton-induced pore pressure. Examples are shown where the anisotropic contribution dominates completely over the isotropic part, and where anisotropy nearly nullifies the isotropic contribution.
Petroleum operations such as hole drilling, production and injection in general may lead to volumetric changes in the underground – also in volumes not directly influenced by injection, production or fluid invasion from the borehole – leading to a change in pore pressure. In an isotropic formation, the volumetric strain results from a change in the mean stress. The undrained pressure change may be described by the well-known B-factor introduced by Skempton in 1954, relating the induced pore pressure to the mean stress.
Skempton (1954) defined his pore pressure parameters A and B in a triaxial context. The definition may be written as
where A and B are Skempton's coefficients, Δpf is the induced pore pressure, (Equation) is the change in mean stress and Δσ1 and Δσ3 are the changes in triaxial stress in axial and radial directions.
For isotropic elasticity the pore pressure responds only to the change in the mean stress. As a result, for isotropic elasticity A=1/3.
A was hence originally introduced to characterize non-elastic effects.
For anisotropic elastic media shear stresses may induce volumetric strain, and hence give pore pressure changes. As a result, the Skempton B must be generalized to a second order tensor, defined by
where summation over repeated indices is assumed here and in the following. The tensorial B in principle relates all stress components to the induced pore pressure.
In this study the performance of the Internet of Fish (IoF) concept, a real-time acoustic positioning and fish monitoring system, was assessed in a commercial marine fish farm in Norway. Central to the IoF concept is the Synchronisation and LoRa Interface Module (SLIM), which is a battery operated surface unit that provides distributed time synchronisation and LPWAN support to a submerged digital acoustic receiver. Six SLIM/acoustic receiver pairs were placed inside a fish cage with acoustically tagged fish at a link-length of 200 m from a centralised gateway. All nodes achieved a Packet Error Rate of less than 8% and a position accuracy of 1.5 m.
Aquaculture is one of the fastest growing food producing industries in the world and is believed to be instrumental in filling the future global supply-demand gap in aquatic food (FAO., 2016). Raising fish in large floating net-based sea-cages have proven as a competitive option due to its flexibility, robustness and cost effectiveness (Føre et al., 2017), despite the generally harsh marine environment and technological and operational challenges it poses to the aquaculture industry. For instance, more than two million tons of Atlantic salmon are produced annually using this farming concept (Liu et al., 2016). The ability to monitor fish behaviour is important, as it is a key element in determining the stress and welfare conditions experienced by the fish in a farm situation (Oppedal, Dempster, and Stien, 2011). In addition, quantifying the movement patterns of fish is critical to understand feeding behaviours, resource utilisation and animal-environment interactions in cages (Espinoza et al., 2011; Biesinger et al., 2013). Acoustic telemetry is fish monitoring concept where individual animals are equipped with miniature electronic devices called transmitter tags that contain sensors and an acoustic modem for wireless underwater data transmission (see Føre, Alfredsen, and Gronningsater (2011) for a more thorough description of the contents of acoustic transmitter tags). This method has been used to observe detailed movement patterns of individual fish by employing source localisation algorithms (Pincock and Johnston, 2012). Previous applications of this approach include tracking of both wild (Espinoza et al., 2011; Biesinger et al., 2013) and farmed fish (Rillahan et al., 2009). Since farmed fish are generally restricted by the confines of the cages, their movement patterns are restricted to be within a much smaller volume than free swimming wild fish. This suggests that it is possible to realise automated positioning systems for aquaculture applications that are more precise than those developed for wild fish monitoring. Considering the large biomass, cage volumes and expected future growth trends in the marine finfish aquaculture industry, a remote monitoring system that can provide input to the day-to-day farm decisions is an essential requirement for realising the benefits and advances of the Precision Fish Farming (PFF) concept (Føre et al., 2017).
Automation is about to bring major changes to the work process for well planning. The next generation well planning tools will take the steps to higher levels of automation, which can provide step changes in quality of the planning, safety aspects in operations and reduce time and cost for planning and operations.
This article discusses the changes that will follow a new standard in well planning and operations. Analysis of the current practices and investigating the potential of a fully automated planning tool leads to a complete re-structuring of the work process. Well planning is a multidisciplinary activity where representatives from the different subsurface disciplines collaborates with the wells engineers in a compromise-prone process often with multiple iterations due to the differences in objective and understanding. The arrival of cross discipline 3D visualization tools has led to improvements in average duration of planning, but it is still a process depending on the efforts of the participating individuals and their level of experience. In an era where computers are landing passenger planes and the pilot has a verification role, it is time to look at the potential in digitalization for well planning and operations.
Many software developers are familiar with the difficulty in developing a "solution" to a challenge in a complex environment such as well construction and production. Many areas of expertise are involved and it is easy to end up with a compartmentalized product which is specialized for one area or a specific challenge. Establishing links and communication to all engineering and calculations in Wells, Subsurface and Production (e.g. well integrity data) are a matter of cost and safety. The next generation well planning tools has to incorporate all areas of expertise from planning well construction, through producing wells to final P&A.
The key enabler for automating the well planning process is the digital experience module, which will be the main task and focus for the Wells Teams. With built in experience, the application has rules and enhanced algorithms allowing Subsurface Teams to make accurate well plans and mature optimal well designs without involving the Wells Teams. Subsurface can identify the optimal drainage and well path including anti-collision, future side tracks, regulations in governing documentation and follow "local best practice". The Wells teams are ultimately responsible and will verify the well path generated by the software, and do any required updates.
Wells closed in due to integry issues compose large volumes of recoverable hydrocarbons. In recent years, there has been advances in the understanding of pipe performance. The understanding of these advances is kept with a few specialists, and the industry standard remains unchanged for most engineers working with well intergrity. This paper shed light on these advances and the impact they have to well integrity. A modest estimate for an average well is an upfront saving potential of ~$45,000 USD for tubulars and a reduction of more than 50 metric tons of CO2 saving of the environment. The larger values, however, is with wells closed in due to integrity marginally under the acceptable. This article shows a hidden design margins. On average, pipe resistance to collapse is ~10 to 25% above the industry standard calculations. And for burst design, the real limit is often more than 7% higher than the industry standard calculations.
Well integrity is a discipline ensuring safe hydrocarbon recovery on behalf of an operator. Every well is scrutinized and every signal outside the set boundaires from a well is ensued until the integrity is understood and a decision can be made to safely produce or to suspend the well. Well integrity is based on performance of the equipment in the barrier envelopes. Pipe is an important element in both the primary and secondary envelopes. Following a better understanding of pipe integrity, a new integrity work flow is proposed. Well Integrity is a relatively young discipline, where guidelines and stanards have evolved significantly over the last decade. There are still several important issues to be standardized, such as the minimum integrity information to be defined for a well. Examples are operational parameters such as (assumed) effective hole diameter, cementing parameters (rate, preflush, slurry, etc.) which have an impact to the integrity. Other important information to standardize is the restrictions in pressure testing of casing to avoid damage of the cement sheaths. Finally, this article proposes "information management" as the 4th element in the definition of well intergrity. The digitalization wave washing over the industry is about making optimal use of data, which is essential to make good decision in well integrity as much as any other area in the oil and gas industry.
The study of hydrogen stress cracking of various Nickel based alloys has recently been reported by others and is a subject of increasing interest. This paper describes results for different test methods, including Slow Strain Rate Testing (SSRT), Incremental Step Loading (ISL), and Constant Load Verification (CLV).
A new Ni-Cr-Mo-Fe alloy UNS N08830 alloy was recently evaluated for resistance to Hydrogen Induced Stress Cracking (HISC), simulating conditions arising during cathodic protection in a subsea environment.
The unique set of test methods and conditions included SSRT and ISL, all using pre-charged specimens with ongoing continuous charging during testing. Test specimens utilized different geometries, including smoothed and notched, along with round and rectangular cross sections.
The paper draws key conclusions based on comparisons of test methods, and also compares UNS N08830 alloy results to other high strength CRA’s used in Oil and Gas subsea production equipment.
Cases of Hydrogen Embrittlement affecting subsea equipment and components have been well documented for some time.1,2,3 The source of embrittlement investigated in this study is theorized to emanate from the evolution of hydrogen gas generated by cathodic protection systems in seawater, with several factors possibly contributing to a material’s susceptibility.4
A joint industrial project (JIP) was formed in 2005 out of Norway to investigate the susceptibility to Hydrogen Induced Stress Cracking (HISC) of duplex and martensitic stainless steels, which resulted in a recommended practice issued in 2008.5,6 More recently, Ni based alloys have been investigated after some field experiences demonstrated susceptibility to HISC.7 NTNU(1) in Norway performed HISC testing in 2014-16 on various austenitic alloys for comparative purposes. To this end, Incremental Step Load (ISL) testing was performed on precipitation hardened nickel alloys along with strain hardened austenitic alloys. One of the alloys included in the study was UNS N08830, a recently introduced new grade suitable for drilling tools for severe oil & gas downhole environments. The nominal chemical composition of the alloy is listed in Table 1.
The new alloy can achieve high yield strength approaching 1170 MPa (170 ksi) through strain hardening, making it a candidate material for various components in tools used for drilling, completions and subsea applications. The alloy retains significant strength at elevated temperatures, giving it advantages over leaner austenitic alloys and super-duplex stainless steels, while offering economic advantages as compared to higher cost Precipitation Hardened (PH)nickel alloys.8
The Society of Petroleum Engineers (SPE) organizes the international student competition Drillbotics. The task is to develop a miniature robotic rig to drill, in a fully autonomous operation, a vertical hole in a 35 cm rock sample with unknown layers – as fast as possible, while maintaining rig integrity and borehole quality. This paper describes the key innovations of the 2nd generation NTNU robotic drilling rig, allowing it to take first place in the 2018 competition.
The rig features a wide operational window for WOB and RPM, achieved by a custom-designed non-aggressive bit, improved BHA design, reinforced drill-string connections and improved rig framework. These improvements allow the rig to drill much faster at high WOB and RPM while avoiding drill-string twist-offs due to over-torqueing or fatigue caused by vibrations.
An autonomous high-ROP mode was employed on the competition day. The best-fit PID controller tuning enables high performance drilling through both soft- and hard formations. Built-in logics automatically detect and handle over-torqueing and stuck pipe.
A novel digitalization framework includes a fit-for-purpose data acquisition and visualization system, data-lake for unified data storage and an automatic well reporting functionality. The system logs all measurements, setpoints and calculations, including WOB, RPM, ROP, drill string torque, stand-pipe pressure, and downhole accelerations and angles (gyroscope).
The NTNU drilling rig managed to drill through a 35 cm competition rock consisting of layers of varying hardness, including a hard tile inclined at 45 deg in 3 minutes and 15 seconds, thus proving its ability of efficient and safe autonomous drilling. The drilling time of the nearest competitor was 15 minutes.
The most important contributer to Improved Oil Recovery (IOR) on mature fields is drilling of infill wells. Managed Pressure Drilling (MPD) and Continuous Circulation System (CCS) techniques can be used for improved control of bottomhole pressure when drilling wells in depleted fields with narrow pressure windows, but rig heave is a challenge when drilling from floating drilling units. Rig heave, caused by sea waves, induces pressure oscillations downhole that may exceed the operational pressure window. These oscillations are called "surge & swab" and occur both during tripping in and out of hole as well as during drill pipe connections, when the topside heave compensation system used during drilling is disabled because the drill pipe is put in slips. Downhole choking was introduced as a method to reduce downhole pressure oscillations induced by the rig heave and the concept was tested in laboratory scale and using computer simulations (
This paper gives an overview of the surge & swab simulator, describing its capabilities and limitations. Data from drilling of a North Sea well is then used to validate the simulations made using the software. The well, used as example in this paper, was drilled conventionally from a floating rig. The downhole pressure variations recorded during three different drill pipe connections are compared with simulated downhole pressure. The simulations are based on the recorded rig heave as well as the actual drilling fluid, well design and drill pipe data. Results show that there is a good correlation between simulated and actual measured downhole pressure. The surge & swab simulation software is then used to simulate the same drilling pipe connections using three different techniques and combinations of techniques utilized for improved downhole pressure control: (1) Managed Pressure Drilling (MPD) (2) Managed Pressure Drilling combined with Continuous Circulation System (CCS) and (3) MPD combined with CCS and a downhole choke. Results show that rig heave-induced downhole pressure variations are reduced to a level which is considered acceptable for drilling a well with narrow pressure window for the last two cases, while utilization of backpressure MPD alone is not sufficient. The combination of MPD and CCS reduced surge & swab for two out of three connections. For the third and deepest connection, the surge & swab increased. The largest reduction in significant downhole pressure variations (43-68 % vs. conventional drilling for the three connections) occurs when MPD and CCS are combined with downhole choking.
Future work will consist of further developing the surge & swab simulator so that it will be possible to utilize it in well planning and as real-time decision support during drilling operations. The simulator will also be developed to include possibility of simulating various well completion operations such as running casings and liners. A prototype of the downhole choke is currently being tested at the mud loop of the Ullrigg test rig facility in Stavanger, Norway, and the next development phase consists of designing and building a complete downhole tool for testing in a well.
Shale plays an important role as cap rock above oil and gas reservoirs and above e.g. CO2 storage sites, as well as being source and reservoir rock in development of so-called unconventional reserves. Shale anisotropy needs to be accounted for in geophysical as well as geomechanical applications. This paper presents a brief description of anisotropic poroelasticity theory, and compares it to its more familiar isotropic counterpart. Experiments performed with field shales are presented, and the static mechanical behavior in terms of drained versus undrained moduli, Skempton parameters and Biot coefficients are shown to be consistent with the poroelastic approach. The necessary steps to provide static properties from seismic data and further link these measurements to laboratory ultrasonic data are briefly discussed.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral