Shell Canada Research Articles

Integrating risk assessment methods for carbon storage: A case study for the quest carbon capture and storage facility

This paper documents how tools developed by the National Risk Assessment Partnership (NRAP) complement the Bowtie risk assessment approach through the demonstration of a risk-based Area of Review (AoR) determination for the Quest Carbon Capture and Storage (CCS) facility near Edmonton, Alberta with the NRAP Open-Source Integrated Assessment Model (NRAP Open-IAM). The Bowtie risk assessment for the Quest CCS site was developed by Shell Canada Ltd., who operates the asset on behalf of the Athabasca Oil Sand Project — a joint venture, owned by Canadian Natural Resources Ltd, Chevron Canada and Shell Canada Ltd. The Quest Bowtie treats site risk comprehensively – considering a large set of technical and project risks (e.g., operational risks, above ground infrastructure, public perception, etc.). NRAP tools, methods, and analyses are focused on quantitative assessment of subsurface technical risks. NRAP-Open-IAM was used to evaluate potential groundwater impacts at the Quest site, i.e., a sufficient change above background groundwater quality levels to be measurable, should CO2 and/or brine leak from the reservoir via a faulty and/or compromised wellbore. Our results show there is a low potential for groundwater impact and support a further reduction (from ∼460 to 100 km2) to the established AoR for the Quest site. Integrating both approaches early in the site characterization period could significantly benefit commercial-scale projects by drastically reducing the region over which leakage risks (e.g., legacy wells) need to be evaluated, i.e., the AoR. This is especially true for brownfield sites, which could contain hundreds to thousands of legacy wells. Further, basing monitoring network design on those regions where impacts are most likely to occur has the potential to facilitate more efficient deployment of monitoring technologies and improve the likelihood of detecting a leak should one occur.

Quest CCS facility: Halite damage and injectivity remediation in CO2 injection wells

The Quest CCS facility (located in Alberta, Canada) is a fully integrated carbon capture, transport and storage facility operated by Shell Canada. It continuously captures and stores about 1.1Mt of CO2 per year. While the initial injectivity for the Quest CO2 injection wells was very high, significant injectivity reductions have been observed. As dry CO2 is injected, water can evaporate from the brine into the CO2 driving precipitation of halite. Plugging of the perforation tunnel and pore throats in the near wellbore area can cause injectivity damage.One method to remediate halite damage is to inject a water-based fluid to dissolve the halite precipitate. Quest performed the first halite remediation treatment on one of the CO2 injector wells in 2020. The objective of this paper is to present the design, execution and results of this initial halite remediation treatment. An outline of the design of the halite remediation treatment will be provided. Subsequently the halite remediation treatment as executed in the field will be reviewed including the timing of operations and the pumping pressure and rate data. Finally, to evaluate the effectiveness of the treatment, skin analysis and injectivity trends pre and post remediation treatment shall be presented.

GHGT-15 Quest CCS facility - Halite Injectivity Damage Remediation in CO <sub>2</sub> Injection Wells

The Quest CCS facility (located in Alberta, Canada) is a fully integrated carbon capture, transport and storage facility operated by Shell Canada. It continuously captures and stores about 1.1Mt of CO2 per year, with injection expected to continue until 2040. Following a month of performance testing, commercial operations began in October 2015, and through November 2020, more than 5.6 Mt of CO2 have been sequestered. The commercial scale deployment of Carbon Capture and Storage (CCS) as a viable greenhouse gas (GHG) emissions reduction technology requires that the CO2 be continuously injected at material and predictable rates into geological formations (e.g. saline aquifers). While the initial injectivity for the Quest CO2 injection wells was very high, significant injectivity reductions have been observed following short well shut-in periods associated with well intervention work. Although these injectivity reductions currently do not form an operational constraint, if the trend of injectivity reductions continue, it may become an issue for future operations. Developing the capability to reduce or even reverse these injectivity reductions may be key to maintaining reliable CO2 injection. The Quest CCS project sequesters CO2 into the Basal Cambrian Sands (BCS) formation, which was initially filled with sodium chloride saturated brine. As dry CO2 is injected, water can evaporate from the brine into the CO2 driving precipitation of halite. This precipitation can occur in various locations including inside the wellbore, perforation tunnel, near wellbore area and further afield in the BCS formation. Plugging of the perforation tunnel and pore throats in the near wellbore area can cause injectivity damage. A downhole video log performed in April 2018 on the Quest IW 7-11 CO2 injection well showed solids plugging in numerous perforations. The most probable substance to precipitate in the downhole environment of a Quest CO2 injector well is halite. While the solids were not sampled for compositional analysis during the April 2018 downhole video log, downhole samples were obtained during the pre-work leading up to the halite remediation treatment. A viable mechanism for inducing halite damage during well intervention shut-in events is that deposited halite is dislodged and subsequently plugs the critical perforation tunnel and near wellbore areas. One method to remediate halite damage is to inject a water-based fluid to dissolve the halite precipitate, thereby removing it from the perforation tunnel and near wellbore area, where it can damage the well injectivity performance. Quest performed the first halite remediation treatment on one of the CO2 injector wells in 2020. The objective of this paper is to present the design, execution and results of this initial halite remediation treatment. An outline of the design of the halite remediation treatment will be provided. Aspects of the treatment design including treatment volume, rate, pressure, treatment fluid composition, fluid diversion, tubing stress analysis and hydrate mitigation will be discussed. Subsequently the halite remediation treatment as executed in the field will be reviewed including the timing of operations and the pumping pressure and rate data. Finally, to evaluate the effectiveness of the treatment, skin analysis and injectivity trends pre and post remediation treatment shall be presented. Halite remediation treatments have the potential to become key methods for maintaining injectivity performance of CO2 injection wells in saline aquifers.

CO2 injectivity behaviour under non-isothermal conditions – Field observations and assessments from the Quest CCS operation

Commercial-scale deployment of Carbon Capture and Storage (CCS) as a viable greenhouse gas (GHG) emissions reduction technology requires that the CO2 be continuously injected at predictably significant and cost-efficient rates into geological formations (e.g. deep saline aquifers).The Quest CCS operation (located in Alberta, Canada) is a fully integrated carbon capture, transport and storage facility operated by Shell Canada. Quest continuously captures and stores about 1.1 Mt of CO2 per year, and it’s expected to continue until 2040. Quest is a dedicated geological storage project (no EOR component) with multiple injectors and monitoring wells. Injection operations started in August 2015 and by mid-October 2018, more than 3.45 Mt of CO2 has been stored using only 2 out of 3 planned injection wells. To date Quest has observed significant injectivity variability relating to seasonal variation in injected CO2 and bottom-hole temperatures.The high-resolution time-series data from the Quest operations gathered over the first 3 years of CO2 injection indicate the standard models of CO2 injectivity leave out some important physics. Prior to the start of injection, theoretical CO2 injectivity at the CO2 injector wells was initially modelled and calculated to decrease by ∼5% - 8% with decreasing CO2 bottom-hole temperature within the temperature range 20 °C–60 °C at the wellbore largely due to increased fluid viscosity at lower temperatures. However, field observations made to date at the Quest CCS site indicate an inverse relationship between CO2 injectivity and bottom-hole temperature, where injectivity increases of up to 10% due to colder CO2 have been observed in the bottom-hole temperature range of 21 °C–33 °C. This paper presents the field observations of injectivity compared to the theoretically expected and modelled 3D isothermal and non-isothermal conditions of injectivity at various CO2 bottom-hole temperatures, together with an assessment of the dominant controlling mechanisms and parameters that could influence CO2 injectivity under non-isothermal conditions. The assessment results indicate that the seasonal CO2 injectivity correlating inversely with bottom-hole temperature (BHT), cannot be explained by CO2 PVT behaviour under non-isothermal conditions. The inverse correlation is driven by near-wellbore permeability (k), relative permeability (kr) and (non-darcy) dynamic skin factor parameters varying in an inverse relationship with bottom-hole temperature through reversible temperature-driven mechanism(s) such as fluid flow regime changes, fluid-rock interactions and thermally-induced micro-fractures leading to increases in dynamic injectivity at lower CO2 bottom-hole temperatures.A full understanding of the non-isothermal processes and their relative impacts on CO2 injectivity are not only crucial for successful deployment of CCS projects but can also have wider beneficial applications in CO2-EOR modelling and operations cost optimisation.

Oil spill settlement funds directed to seabird conservation

Settlement funds from catastrophes can generate lasting conservation benefits, if directed appropriately. Such is the case with the Nestucca oil spill which occurred in Washington State in 1988. The spill killed thousands of marine birds and the subsequent litigation settlement awarded 3.3 million dollars for recovery and monitoring of Canadian seabirds, in addition to clean-up costs. Settlement damage funds were directed to eradicate introduced rats from Langara Island, to restore what was formerly the world's largest colony of Ancient Murrelets (Synthliboramphus antiquus). In addition, settlement funds were devoted to establishing an ecosystem-level baseline of seabirds and their marine prey populations on Triangle Island, the largest and most diverse seabird colony in Western Canada. One of the projects tracked breeding Cassin's Auklet (Ptychoramphus aleuticus) and determined that they foraged far away from the colony in search of deep-sea copepods. The results stimulated conservation planners to enlarge a marine protected area which had been proposed to protect marine birds in the region, but policy guidance was lacking. By 2018 policies had evolved, and Canada announced the formation of their first marine National Wildlife Area following a multi-year engagement process with many interested parties. At the same time, Shell Canada relinquished all of their exploratory drilling rights within the area. The settlement funds from a catastrophic oil spill facilitated the recovery of seabirds on Langara Island, the formation of the first marine protected area for wildlife in Canada, and a reduction of future threats from exploratory drilling in an internationally important ecosystem.

Extreme Limited-Entry Design Improves Distribution Efficiency in Plug-and-Perforate Completions: Insights From Fiber-Optic Diagnostics

Summary Limited-entry (LE) plug-and-perforate (PnP) fracture designs were pioneered in the early 1960s as a cost-effective technique to stimulate multiple pay zones with varying stress regimes (Murphy and Juch 1960). Conventional completion techniques involved blanket perforating the entire interval at a certain number of shots per foot (spf). The LE technique was revolutionary in that it recommended “limiting” the number of perforations to distribute fracture-stimulation fluids into multiple intervals with differing stress regimes. However, diagnostics have shown that LE-treatment distribution during the slurry phase is uneven, and is highly affected by several key parameters that may change significantly during treatment. Several papers have been published on the inefficiencies associated with LE design and what can be performed to overcome them (Ugueto et al. 2016; Somanchi et al. 2016). Shell Canada Limited recently tested extreme limited-entry (XLE) designs to determine if additional pressure drop across the perforations would improve treatment distribution. Stages were alternated with differential perforation friction (ΔP) pressures of 2,000, 2,500, and 3,000 psi to determine if there was a threshold ΔP that would result in a more-optimal treatment distribution. However, because of wellhead-pressure limitations, actual ΔPs were below the design values. There were no placement issues associated with fewer perforations and higher treatment pressures. The trial well was completed with thirteen three-cluster stages. All clusters were spaced evenly at 50 m and fracture-stimulated with a slickwater system with 31 tons/cluster (93 tons/stage). The fracture stimulation was monitored with an externally clamped fiber-optic (FO) cable. Treatment distribution and production were quantified by using distributed acoustic sensing (DAS) (Molenaar and Cox 2013). Post-job analysis indicates a 40% improvement in distribution compared with previously stimulated three-cluster standard LE completions. With the XLE design, 100% of the clusters received some proppant. There is a 33% increase in cluster activity at IP90 (initial production on the 90th day) from the XLE design compared with a previously completed three-cluster conventional LE well. Improvement in distribution is minimal beyond ΔP of 1,200 psi during the pad phase. However, this threshold could be rock-specific and needs to be validated with trials in different play types. Data also suggest that treatment pressure should be maintained at a maximum throughout the pad and slurry placements, within equipment and wellhead limitations. During the pad, this is important to ensure breakdown and fracture extension. In the slurry phase, maximizing out pressure helps to maintain ΔP across eroding perforations. In some plays, insufficient ΔP may prevent all clusters from breaking down. In Groundbirch, typically all clusters break down and take fluid from the start but screen out as soon as sand hits. Typically, slurry rate was not increased to compensate for the loss in ΔP associated with an increase in perforation diameter. These factors are mainly responsible for the heel-vs.-toe bias in LE designs, which results in undertreatment of toe clusters (Ugueto et al. 2016).

IEAGHG Summary Report of the Shell Quest Carbon Capture and Storage Project

In August 2015, Shell Canada began sustained, commercial-scale operation of the first-ever CO2 capture facility at an oil sands bitumen or heavy oil upgrader in the world, along with a dedicated pipeline and geological storage of the carbon dioxide at a nearby, sole-purpose site. This project is located at its Scotford Complex near Edmonton, Alberta, Canada. The C$1.35 billion Shell Quest project was conceived in 2008. By the end of the second year of operation in December 2016, Shell Canada and its project team achieved many firsts that are outlined in this brief paper summarizing the poster presented at GHGT-14, along with key successes of the project.

Design and Surveillance Tools Help Lower Integrity Risks for High-Temperature Wells

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184159, “Use of Technical Design and Surveillance Tools To Minimize Operating Integrity Risk in High-Temperature Wells,” by Mirko Zatka, SPE, Shell Canada Energy, prepared for the 2016 SPE International Heavy Oil Conference and Exhibition, Mangaf, Kuwait, 6–8 December. The paper has not been peer reviewed. Thermal-well operations come with significant additional complexity in regard to maintaining wellbore integrity and hydraulic isolation from other formations. This is because of the extreme loads that may be placed on the well casing and liners, caused by the wide set of operating temperatures and pressures the wellbores may experience. To ensure that the wellbores can fulfill their anticipated operating need safely, careful design of the casing, liners, connections, and cement during the project-development phase is an absolute requirement. Background Wells designed for heavy-oil thermal-recovery projects will be exposed to a potentially wide range of operating temperatures. These can exceed 340°C for the deepest heavy-oil-bearing formations and can be as low as 5°C during well workovers. Such a range of operating conditions will cause the casing to yield under compressive conditions, and most likely under tensile conditions also, as it undergoes thermal cycling from the heating and cooling requirements of well operations. A thermal cycle is defined here as the confined casing material being heated to the point that it yields and plastically deforms under a compressive load, followed at some later time by sufficient cooling to force it to yield and plastically deform under a tensile load. This is an operating requirement for which casing and liners are not normally designed in conventional applications but is frequently unavoidable in thermal operations. As a result, consideration of material properties of the tubulars requires a much deeper understanding of the chemistry, manufacturing, and heat-treating processes in order to select the optimal material. Similarly, casing connections play a key role in well integrity, based on their ability to withstand stress cycles in the casing or liner string. Casing-cement composition and placement procedures are also key design parameters because thermal cycling of the casing will expose the cement to very large stresses across the metal/cement bond and potentially can alter the cement properties themselves. In turn, the operating practices applied to wellbores and the operating envelopes used to determine safe limits become keys to long-term integrity and safety.

The Quest CCS Project: 1st Year Review Post Start of Injection

In September 2012, the final investment decision was taken to move ahead with the Quest Carbon Capture and Storage (CCS) project in Alberta, Canada. Quest is the world's first CCS project linked to an oil sands bitumen upgrader. The operator is Shell and the project is part of a joint venture between Shell Canada Energy, Chevron Canada Limited, and Marathon Oil Canada Corporation. On the 23rd of August 2015, CO2 injection commenced at two of three available injection well sites. On 29th September 2015, the commercial operations’ certificate for Quest was issued. During the first year of operation, the target of injecting 1 million tonnes of CO2 per year was reached ahead of schedule. Individual components of Quest have been very reliable, including surface facilities related to the capture and transport of the CO2, wells, and the storage reservoir. The uptime during the first year of operation was over 99%. The CO2 is safely contained within the storage complex, as there has been no indication of a loss of containment. A key part of making this a successful project has been the on-going engagement with stakeholders.

Good for the Economy? An Ecological Economics Approach to Analyzing Alberta’s Bitumen Industry

Competing claims about the economic, social and environmental impacts of bitumen projects make Alberta's oilsands industry highly contentious. This paper uses a case study of a major bitumen project, Shell Canada's Jackpine mine expansion, to examine the evidence considered by government decision-makers in the project approval process. The project was determined to be “in the public interest” based primarily on its economic benefits, despite significant adverse environmental and social impacts. The paper evaluates the evidence that was presented to support this decision, using three criteria drawn from ecological economics: efficient allocation, just distribution, and sustainable macroeconomic scale. It finds that the evidence presented is, in fact, insufficient to justify the project on any of the three criteria. Furthermore, other studies of the bitumen industry cast doubt on the likelihood that the project would satisfy these criteria if further analysis were conducted. It concludes by recommending several measures that could help to improve decision-making on bitumen projects in the future.

Impact of the Prairie Evaporite dissolution collapse on McMurray stratigraphy and depositional patterns, Shell Albian Sands Lease 13, northeast Alberta

Abstract The Cretaceous McMurray Formation in NE Alberta contains nearly a trillion barrels of bitumen, a significant portion of which is being developed via surface mining and in-situ thermal methods. The focus of this report is the structure and stratigraphy of the Cretaceous McMurray Formation and its relationship to the configuration of the underlying Devonian section in the area of Shell Canada’s Albian Sands Lease (Township 95, ranges 9 and R10W4M), a joint oil sands mining venture between Shell Canada (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). The structural and stratigraphic relationships between the two intervals has been the source of several recent investigations due to industry related incidents that demonstrated the integrity of the underlying Devonian succession can be compromised by vertical pathways associated with faults, sinkholes, or other features. Key findings of this work include the following: The present morphology of the Pre-Cretaceous unconformity is primarily due to structural deformation (differential subsidence) related to dissolution and collapse of the underlying Prairie Evaporite Formation and overlying Devonian units of the Beaverhill Lake Group rather than erosion relief. Two types of collapse structures are recognized: a) large scale sag folds that are 1-to-10 kilometres in extent; and b) small scale breccia pipes that are 10- to-100 metres in diameter. The sag folds are interpreted to have formed in response to the dissolution of halite. The breccia pipes, which postdate the sag folds, represent sinkhole features that formed in response to the dissolution of gypsum. Rather than onlapping the unconformity, Lower McMurray strata thin and converge across structural highs and thicken and diverge across structural lows, demonstrating much of the dissolution driven subsidence was contemporaneous with the deposition. The subsidence produced up to 80 metres of accommodation and involved the coherent sagging and faulting of large intact segments of the underlying Devonian section. The arrangement of major stratigraphic packages indicates subsidence features shifted locations through time rather than persisting through the entire Lower McMurray. Changes in sedimentation style between sand-rich fluvial packages to mud-rich lacustrine dominated packages within the lower McMurray reflect changes in relative rates of subsidence. Sand-rich fluvial units are localized in settings with low-to-moderate subsidence rates, while mud-rich fluvial-lacustrine units are localized in settings with moderate-to-high subsidence rates. The Middle-to-Upper McMurray section is composed of four high relief unconformity bound units that display flat/horizontal stratal relationships with the underlying structure of the Pre Cretaceous unconformity. In contrast to the Lower McMurray, stratigraphic relationships indicate it was largely impacted by falls and rises in relative sea-level (cycles of negative and positive accommodation) rather than dissolution driven subsidence that, while still active, had begun to wane.

Technology Focus: Coiled Tubing Applications (June 2016)

Technology Focus Another tough year has passed since the last coiled-tubing feature in JPT. In spite of the difficult economic climate, the SPE/ ICoTA Coiled Tubing and Well Intervention Conference and Exhibition moved to a new venue this year, the George R. Brown Convention Center in Houston, because of the continued growth of the exhibition in prior years. Attendance was down by only a small percentage, which, I hope, is an encouraging sign. As mentioned in last year’s feature, the coiled-tubing industry is adapting to the changing environment. Several papers at this year’s conference discussed various aspects of subsea work performed with coiled tubing. Two papers presented different methods to use coiled tubing to enter or drill wellbores by using either an injector or a snubbing jack at the seabed and a secondary coiled-tubing injector at the surface. In both methods, the coiled tubing runs freely through the water— that is, the coiled tubing is not contained within a secondary riser pipe—and, hence, many in the industry are referring to this new technique as riserless coiled tubing. Other subsea operations mentioned included the use of coiled tubing as a downline for pumping fluids from a vessel to a subsea tree or pipeline. While this is not new to the coiled-tubing industry, tooling and vessel-based-equipment improvements have been developed to make operations safer and more versatile. Also in this arena, new thermoplastic composite materials are being introduced to the market and may bring further enhancements. These types of developments require considerable investment on behalf of the companies involved and tend to signal confidence in the longer-term return. Meanwhile, investment in furthering the understanding of the performance of steel materials for coiled-tubing well-intervention operations continues to grow. This performance envelope is being examined in terms of both the mechanical (e.g., abrasion and fatigue) and the environmental (e.g., sour-well environments). For example, renewed studies are being conducted on the combination of high-cycle elastic and low-cycle plastic fatigue, which currently has relevance to subsea work. Formerly, such studies were limited to the use of coiled tubing as a pump string. Additionally, established knowledge of solids transport in high-angle wells, from both field experience and laboratory work, is being applied more widely to reduce costs through increased efficiency. This has been a long implementation curve for the coiled-tubing industry. The next 12 months could bring upturns and downturns and greater or lesser volatility. Whatever may happen, the coiled-tubing industry’s record last year indicates that it will still be moving forward. Recommended additional reading at OnePetro: www.onepetro.org. SPE 179096 Localized Extreme Coiled-Tubing Wall Loss—Causes and Remediation Practices by Steven Craig, Baker Hughes, et al. SPE 179083 Novel Abrasive Perforating With Acid-Soluble Material and Subsequent Hydrajet-Assisted Stimulation Provide Outstanding Results in Carbonate Gas Well by Alejandro Chacon, Halliburton, et al. SPE 168294 Coiled-Tubing-Material Selection for Velocity Strings in Sour Brine Service by I. Ward, Shell Canada, et al.

Solvent-Enhanced Steamdrive: Experiences From the First Field Pilot

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 175414, “Solvent-Enhanced Steamdrive: Experiences From the First Field Pilot in Canada,” by M.L. Verlaan, SPE, and R. Hedden, SPE, Shell Canada; and O. Castellanos Díaz, V. Lastovka, SPE, and C.A. Giraldo Sierra, Shell Chemicals Americas, prepared for the 2015 SPE Kuwait Oil and Gas Show, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed. In recent years, the addition of a hydrocarbon condensate to steam operations in heavy-oil and bitumen reservoirs has emerged as potential technology to improve not only oil recovery but also energy efficiency. The idea of solvent addition to a steamdrive process has been extended and applied for the first time in the Peace River area in Canada. There, evidence was obtained of oil uplift in the patterns where solvent was injected. However, piloting this new technology in a brownfield had many challenges, especially when evaluating its main economic factors: production increase and solvent recovery. Introduction Vertical-well steamdrive (VSD) is the selected process to recover bitumen from the Peace River Bluesky formation. Solvent coinjection has been identified as an economical method to improve the efficiency of this process. In an early phase of the steamdrive, a slug of hydrocarbon condensate (diluent) is coinjected with the steam. The solvent condenses at the cold steam/bitumen interface to form a solvent bank. This bank has the potential to accelerate bitumen production by viscosity reduction and to improve ultimate recovery. The efficiency of the diluent coinjection in a steamdrive process is expected to be lower than that of liquid addition to steam for enhanced recovery; however, the solvent recovery factors are expected to be much higher. The solvent recovery, therefore, is a key factor in the economic viability of the process. The main objectives of the pilot were to obtain a positive response in bitumen production and accurate quantification of the diluent recovery. An accurate assessment of the bitumen-production increase was not expected because of the small size of the pilot and lack of control patterns; hence, the injection slug size and concentration were designed to obtain a significant and measurable bitumen response. Pilot Design The Peace River lease in Alberta, Canada, has been subject to many well-and recovery-technology trials in the last 30 years. One of the technologies tried is cyclic steam stimulation (CSS) with multilateral horizontal wells. Pad 19 has been developed with so-called “soak radial wells”—four horizontal laterals in a cross pattern. Over a 9-year time frame, bitumen has been produced in seven to eight CSS cycles. With a recovery of less than 20% from the initial design, a part of the pad has been converted to a pattern steamdrive to increase recovery to more than 50%. Vertical injectors and producers are drilled to complete the 5-acre inverted- fivespot patterns. Vertical producers are perforated over almost the complete interval, while steam injectors have been completed with five limited-entry perforations (LEPs) to distribute the steam evenly over the entire reservoir interval.

Technology Focus: Water Management (December 2015)

Technology Focus Horizontal drilling followed by multistage fracturing is the most prevalent mode of hydrocarbon extraction from shales. Hydraulic fracturing of a well encompasses, on average, approximately 30 fracturing stages, with each stage using approximately 3,800 bbl of fresh water, equating to approximately 114,000 bbl for each well. The need for such vast amounts of fresh water in hydraulic fracturing significantly affects water availability and sourcing and the cost and logistics of accessing and trucking the water to the wellsite. Furthermore, regulations designed to protect communities and the environment from potential sources of contamination are becoming increasingly stringent. Approximately 10–30% of the fresh water injected into a well during fracturing treatments returns to the surface along with various amounts of formation water, henceforth referred to as produced water. Thus, in the interest of conservation and sustainability, it is highly desirable to maximize any opportunity to reuse the produced water for subsequent fracturing treatments. Produced water usually contains residual hydrocarbon; high levels of total dissolved solids (TDS), including sodium, calcium, magnesium, barium, and other salts; suspended solids; and residual production chemicals. Reclaiming produced water as the base fluid for hydraulic fracturing not only helps to alleviate the industry’s dependence on fresh water but also lowers the overall cost of the fracturing operations. Conventional fracturing-fluid systems require fairly low TDS to achieve stable rheology, so produced water requires extensive treatment before it can be used for fracturing. There have been attempts to develop fluids that can be prepared with produced waters that contain a limited amount of TDS, typically less than 30,000 ppm. However, several operating areas, including the Haynesville, Marcellus, and Bakken shales and west Texas areas, have produced waters with much higher salinity (TDS concentrations greater than 150,000 ppm). An ideal solution would be to reuse the high-TDS produced water in subsequent fracturing treatments with minimal filtration to remove the suspended solids. In response, a growing group of chemical suppliers, researchers, and service companies are on a mission to develop fracturing fluids using high-TDS produced water as a base fluid that provides a stable rheology. The papers featured this month deal with the formulation of stable fracturing fluid from high-TDS produced water. I urge you to look at OnePetro, the SPE online library, and download papers. You will find updates on best practices, case studies, new fluid formulations, and much more. JPT Recommended additional reading at OnePetro: www.onepetro.org. IPTC 18142 Slickwater Chemistry Concerns and Field Water Management in Tight Gas by David Langille, Shell Canada, et al. SPE 173371 Chemical Compatibility of Mixing Utica and Marcellus Produced Waters: Not All Waters Are Created Equal—A Case Study by F.B. Woodward, Shell Exploration & Production, et al. SPE 173324 The Freshwater Neutral Challenge: The Need for Protection, Reduction, Innovation, and Conservation by R. Greaves, Southwestern Energy, et al. SPE 173372 Overcoming Obstacles for Produced Water in Bakken Well Stimulations by Darren D. Schmidt, Statoil, et al.

Technology Focus: Completions (September 2015)

Technology Focus Like a fingerprint, every completion is unique and gives each well its own identity. The hardware selection, its deployment method, and the associated stimulation technique combine to create a one-of-kind completion, custom tailored for each application. It is this infinite variation that constantly fuels a collective desire to bring stability to the completion process. More so than ever before, the themes of efficiency and optimization serve as a backbone for completion design and execution. These themes remain valid under any market condition but become all the more significant in challenging or volatile climates. Well completions play a critical role in the overall productivity of a reservoir, which inherently drives the decision-making processes toward well efficiency and production optimization. While there are many gains to be had around more-efficient hardware and stimulation deployment, improving the overall well efficiency and optimizing the production profile through carefully designed and implemented completion strategies represent the true endgame. The challenge lies in accessing the key ingredient that enables harmonization of all the various components: data. Today, full-field studies comparing varying completion techniques with associated production performance are commonplace to evaluate and home in on optimum completion methods. Sensing technology, common to drilling and evaluation, continues to be integrated into completions, providing a front-row seat for the main event, production. The adage “knowledge is power” could not be more relevant in this context. Data collection and analysis, and subsequent controls, are what ultimately will enable the most-efficient and -optimized wells. The papers highlighted in this feature speak to these themes that have become ever-present within the completions community. This selection of case histories and new technology reinforces the inherent desire to achieve stability through efficiency and optimization, even under the most challenging of market conditions. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 170264 Electronic-Set Openhole Packer Installation in Campos Basin, Offshore Brazil: A Case History by G.D. Mendes, Baker Hughes, et al. SPE 170694 Acid-Soluble Plugs— Pressure-Tight Solution for a Preperforated Liner by E. Livingston, ConocoPhillips, et al. SPE/IADC 170547 Innovative Intelligent Multizone Gravel-Pack Completion Revives Production in Malaysian Brownfield by T.U. Ceccarelli, Schlumberger, et al. SPE 170738 Composite-Plug-Milling Efficiency Improvement Through Rheology Control—Lessons Learned From the Horizontal Completions in the Devernay Shale by Darren Huynh, Shell Canada, et al.

Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16762, ’Successful Fracture Stimulation in the First Joint-Appraisal Shale-Gas Project in China,’ by Liang Jin, Changlong Zhu, Yong Ouyang, Ming Zhou, Qingguang Qu, Fei Li, Roger Yuan, Chris Wu, Zhiyi Zhang, Yan Wang, and Fa Dwan, Shell China Exploration & Production; Sanjay Vitthal, Shell Canada; and Shiqian Wang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. This paper discusses fracture stimulation in the first joint-venture shale-gas project with foreign companies in China. The block is in Sichuan province, and the target zone is Longmaxi hot shale, a Silurian formation. Its matrix permeability is extremely low (100 to 300 nanodarcies), but it is rich in natural fractures. Hydraulic fracturing has been shown to be critical to enhancing production. A collaborative approach was applied to the completion of the shale gas wells during appraisal. Introduction Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. China’s technically recoverable shale-gas resources are estimated at 1,275 Tcf. The operator jointly appraised a shale-gas block in Sichuan with PetroChina. The project team needed to make several determinations in the early phase of the project, such as whether there is sufficient gas in the shale formation and whether the gas can be extracted at a high-enough (commercial) rate. From the production technologists’ perspective, the technical objectives of the early wells included the following: Test the ability of the Longmaxi hot-shale interval to be fractured under high formation pressure. Establish baseline fracture designs for the Longmaxi hotshale interval, at greater than 3500-m true vertical depth (TVD), and systematically evaluate the design parameters. Establish an effective multidisciplinary workflow. Gather fracture-stimulation-performance data and subsurface-pressure information. Determine the productivity of the gas from the appraisal wells to prove the presence of a shale-gas play. The joint-appraisal phase began in November 2010. While planning the drilling of deep wells to evaluate the Longmaxi formation, data were obtained from several shallow wells at a location close to the surface. Extensive laboratory tests were conducted to evaluate the geochemical properties of the rock. In addition, some rock-mechanics properties were measured. The drilling of the first well (Well A) began in December 2010, and hydraulic fracturing began once the well reached designed depth. To date, five wells have been drilled; two are vertical, and three are horizontal.

Investigation of Natural Tracers for MMV at the Quest Carbon Capture and Storage Project, Alberta, Canada

Abstract In 2015, CO 2 injection will start at the Quest Carbon Capture and Storage (CCS) Project in Alberta, Canada. The Quest Carbon Capture and Storage (CCS) project is a joint venture between Shell Canada Energy, Chevron Canada Limited, and Marathon Oil Canada Corporation, and is operated by Shell. The CO 2 is captured from the Scotford oil sands bitumen upgrader, located northeast of Edmonton. Up to 1 Mt of CO 2 per year will be injected into the Basal Cambrian Sandstone (BCS), a saline aquifer located at a depth of about 2 km below ground surface, over a potential time period of 25 years. In order to demonstrate containment and conformance of the injected CO 2 , implementation of a Measurement, Monitoring and Verification (MMV) plan is essential. A number of technologies can be used within a MMV plan, such as geophysical or geochemical techniques. The latter may include chemical and/or isotopic fingerprinting of specific fluid end-members, such as the BCS brine. The aim of this paper is to provide an overview of the work that has been undertaken to assess the use of natural tracers for MMV purposes at the QUEST CCS project. The two key objectives are to a) review chemical and isotopic compositions of the BCS brine compared to overlying aquifer waters, and b) to assess the suitability of the natural abundance C and O isotopic compositions of injected CO 2 as a tracer.

Lowering Impacts of Natural Gas Drilling in Dawson Creek, BC, Canada

Growing global energy demands has increased the use of hydraulic fracturing for the economic extraction of the world’s shale gas. The increase has raised concerns from stakeholders about the impact on the environment, drinking water and human health. As a major producer of shale gas, Royal Dutch Shell has developed a set of five operating principles to address the concerns of safety, footprint, air, water and community. The collaboration between Shell Canada and the City of Dawson Creek on a reclaimed water facility in northeastern BC exemplifies these principles. Benefits to the Dawson Creek as a result of the facility include a reduction in: water taken from the Kiskatinaw River; treated sewage (926/100ml faecal coliform) discharged to Dawson Creek; and water transferred between the Kiskatinaw and Pouce Coupe watersheds. An 85% reduction in discharge to Dawson Creek will improve dilution rates during periods of low flow when a majority of the flow is due to the City discharge. Using reclaimed water for industrial purposes alleviates the strain on the growing community’s drinking water supply and the sale of reclaimed water also provides a new revenue stream for the municipality. Benefits to Shell include: virtual elimination of Shell’s draw on fresh water in the area by providing guaranteed access to reclaimed water. A pipeline will link the reclaimed water facility to Shell’s central water hub where it will be mixed with flowback water for future fracturing operations. The pipeline is expected to eliminate 3,000,000 km a year of heavy road traffic, over the course of full field development, resulting in: reduced diesel exhaust, road dust, and noise as well as increase road safety. The Dawson Creek reclaimed water facility demonstrates how sound operating principles and innovative collaborative agreements can result in significant advances in sustainable development. This project alone has made strides in river health, air quality and road safety.

New Time/Rate Relations for Decline-Curve Analysis of Unconventional Reservoirs

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 162910, ’Practical Considerations for Decline-Curve Analysis in Unconventional Reservoirs - Application of Recently Developed Time/Rate Relations,’ by V. Okouma, SPE, Shell Canada Energy; D. Symmons, Consultant; N. Hosseinpour-Zonoozi, SPE, and D. Ilk, SPE, DeGolyer and MacNaughton; and T.A. Blasingame, SPE, Texas A&M University, prepared for the 2012 SPE Hydrocarbon Economics and Evaluation Symposium, Calgary, 24-25 September. The paper has not been peer reviewed. This work presents a workflow that can be used to analyze and forecast time/rate data of wells in low- and ultralow-permeability reservoirs. The key component of the workflow is the application of diagnostic plots to guide the analysis and obtain model parameters for a given time/rate relation. Once model parameters are obtained, the production profile is extrapolated to yield the estimated ultimate recovery (EUR) at a specified time limit or abandonment rate. Introduction The starting point for any discussion of decline-curve analysis for unconventional reservoirs must be an understanding that no simplified time/rate model can accurately capture all elements of the performance behavior. In addition, no time/rate model can be expected to pro-vide a completely unique forecast of future performance or prediction of EUR. It is important to be both realistic and practical when attempting to characterize production performance from systems where the permeability is on the order of 10–500 nd, the reservoir flow system is complex, and, although the induced-hydraulic-fracture system enables (and dominates) the production performance, there is only the most rudimentary understanding of the flow structure in the fracture systems. It is essential that these conditions be established as a starting point. Not doing so will inevitably lead the analyst to interpretations based on incorrect assumptions as well as significant bias. The authors assert that reasonable production forecasts and predictions of EUR can be made, but not in isolation, not solely looking at the data and the selected time/rate model. The analyst must consider the nature of the resource and the significant uncertainty in the ability to apply simple time/rate relations to a very complex reservoir system. As an attempt to better represent the general character of time/rate production data for a multistage-fractured horizontal well in an ultralow-permeability reservoir, numerous authors have developed time/rate relations using certain specific bases to represent a particular scenario. These developments include the following time/rate relations: Power-law exponential model Stretched exponential model Logistic growth model Duong model

Focus on Unconventional Reservoirs Requires Advancements in Technology

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163988, ’Practical Insights and Benefits of Integrating Technology Into Exploration, Appraisal, and Development of Unconventional Gas and Liquid- Rich Shale Reservoirs,’ by Bora Oz, SPE, David Braun, SPE, Sanjay Vitthal, SPE, Viannet Okouma, SPE, Mathieu Molenaar, SPE, Chandran Peringod, SPE, Sergei Kazakoff, SPE, Yongyi Li, Michele Asgar-Deen, and David Langille, SPE, Shell Canada, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed. In the current high-oil-/low-gas-price North American environment, and considering the new options available for well-completions technology in unconventional reservoirs, recent industry activities have turned their focus to the areas of liquid-rich shale (LRS) and light tight oil (LTO) along with unconventional tight and shale gas. Integrated workflows are important to the successful execution of this portfolio, and cutting-edge integrated technologies must be viewed as key enablers. Introduction Commercially and economically viable shale plays require the presence of some key conditions, which fall into two groups: reservoir quality/productivity and fracability (i.e., the ability to place effective and conductive stimulations). Factors that affect reservoir quality and productivity are the matrix porosity and permeability, organic carbon content, maturity and kerogen type, and fluid composition and pressure/volume/temperature properties. Two key factors that affect fracability are mineralogy and local in-situ-stress magnitude, orientation, and distribution. To develop unconventional gas (UG), LTO, and LRS plays more effectively, significant advancements in understanding geological, geophysical, geochemical, geomechanical, petrophysical, reservoir, and stimulation properties have been made in the last decade. However, we are still just scratching the surface, and rapid integration across disciplines is required for success. In addition, continuous learning from exploration through to the end of field life must occur. Geophysical Practices and Technologies Geophysical technologies have always played a crucial role in the exploration and development of unconventional resources. They are used to define subsurface properties and to detect and monitor microseismic activities in the subsurface during completion and production. The recent, rapid increase in unconventional appraisal activity and the large diversity of geological settings require continuous innovation in geophysical-data collection, processing, and interpretation. Engineering activities, such as well and completion design, hydraulic-fracture monitoring, and production analysis and forecasting, are the major drivers for geophysical technologies. The three most common geophysical technologies are surface seismic, nonseismic methods (mainly potential-field methods), and microseismic or other downhole acoustic techniques (Fig. 1). For exploration and appraisal, a large number of 2D-seismic lines, with limited 3D-seismic surveys, are required data sets. In the development stage, 3D-seismic data are crucial for reservoir characterization and well placement (as well as engineering-related applications). Advanced interpretations have become an essential part of understanding play complexity, optimizing well placement, and mitigating drilling geohazards. Seismic data also play an important role in providing geological boundaries for building geological frameworks and geomechanical models.