Legacy Wells Research Articles

Risk assessment and management strategy of geologic carbon storage in multi-well site

Many oil and gas production areas may serve as potential geologic carbon storage(GCS) sites, but large-scale CO2 injection in these sites with multiple legacy wells poses a leakage risk. Therefore, it is crucial to analyze the well leakage risk of these GCS sites and develop effective risk management strategies to minimize CO2 and brine leakage. In this study, we hypothesized a GCS site based on the Jingbian area in the Ordos Basin, which has 177 legacy wells. We conducted a three-dimensional geological modeling of the site and simulated the injection and migration of CO2. Using the National Risk Assessment Partnership’s open-source Integrated Assessment toolkit, we outlined a workflow for assessing the risk of CO2 and brine leakage in multi-well site. Simulations of CO2 and brine leakage through 177 existing wells into the USDW or the atmosphere are used as an indicator of potential risk. Finally, we proposed risk management strategies based on well integrity, injection rate, and pollution range, verifying their effectiveness. The results of the 95th percentile (P95) model implementation showed that the leakage risk of GCS sites was low over 150 years, with a CO2 leakage of 15,996.4 tonnes(0.16 % of the 107 t injected). The risk-based strategy outperformed both distance-based strategy and hybrid strategy overall. Reducing injection rates alone proved ineffective as a risk management strategy. Only high-risk wells near the injection zone may cause pollution to USDW. Meanwhile, legacy wells have negligible impact on atmospheric pollution. The management strategy based on pollution range can be used as a supplement to the risk-based strategy in practical engineering.

Site characterization of the Endurance CO 2 store, Southern North Sea, UK

The Endurance saline aquifer CO 2 store in the UK North Sea is the planned storage site for CO 2 emissions that will be captured from the East Coast Cluster. The site has been characterized to assess its suitability for injectivity, containment and capacity. The injection target is the Early Triassic Bunter Sandstone Formation, consisting of fine-grained sandstones deposited in fluvial, lacustrine and playa lake environments that were subject to repeated aeolian and fluvial reworking. The sandstones have excellent reservoir quality and are likely to be well connected due to the lack of preserved heterolithic layers. The trap is a large, four-way dip-closed anticline, sealed by mudstones and evaporites of the Middle Triassic Dowsing Formation. The top seal sediments are laterally extensive and geomechanically strong, and faulting observed in the overburden does not appear to connect to the reservoir, providing confidence that CO 2 containment will be secure. The risk of leakage through existing legacy wells is assessed as low. The maximum effective CO 2 storage capacity is c . 450 Mt: Phase 1 development of 100 Mt is equivalent to a storage efficiency factor of 3%, which is achievable without the need for brine production. First injection is planned from 2027.

Quantitative assessment of well leakage, part I: Cement stress evolution

A damaged cement sheath in wells can open a leakage pathway to shallow freshwater aquifers and atmosphere. Quantitative assessment of leakage along wells has become an area of interest for both the industry and the regulatory bodies. The well leakage can be of importance in both active and legacy wells. In order to estimate leakage through cement sheaths, the size of the leakage pathway and the damage in the cement sheath must be estimated. In this work, we have developed a hydro-thermo-mechanically coupled near-well model that aims to calculate the evolution of cement’s stress as it cures. This process takes into account the cement’s gradual increase in stiffness, chemical shrinkage, and the heat of hydration. The results are verified using lab measured cement stress and pore pressure data from the literature. A case study was developed based on a low-enthalpy geothermal doublet in the Netherlands. The results show that during the cold water injection, an outer microannulus may open to 60 µm. The presence of an external source of water and formation stiffness are of significant importance in determining the damage to the cement sheath. The heat of hydration in cement increases the temperature of cement during curing. The subsequent drop in temperature due to drilling or completion reduces the cement stress and exacerbates the damage to the cement sheath. The producer well may not form a microannuli, however shear and cyclical failure may be of higher likelihood. The modelling framework presented here allows for estimation of annular cement stress in the well. The analysis provides quantitative estimates of the size of the leakage pathway along a well that can be used to estimate well leakge. Quantitative estimate of well leakage provides crucial information for quantitative risk analysis and provides a framework to optimize well operations to minimize leakage risk.

Predicting the thermal regime of the Po Plain subsurface (Italy) using geostatistical modeling constrained by legacy wells

Italy boasts a long history of hydrocarbon exploration. The Po Basin, in particular, has been extensively explored due to its peculiar geological setting, arising from the convergence of the Southern Alps and Northern Apennines. Because of this, substantial subsurface data have been collected and made publicly available. Today, data from past oil and gas exploration campaigns can find new life in decarbonization programs, especially for geothermal exploration. Geothermal data on the Po Basin, including bottom hole temperature (BHT) and drill stem test (DST) records, play a crucial role in understanding the thermal state of the subsurface, and can therefore be employed in the exploration of geothermal resources. This study presents a 3D model of the thermal regime in the Po Basin based on the analysis of legacy hydrocarbon wells. Geostatistical models of subsurface temperatures are produced via direct sequential simulations that consider: (i) the overall geothermal gradient across the region, (ii) anisotropy in the temperature field revealed by variogram analysis, and (iii) temperature data in the surrounding geological volumes. A base-case model of expected temperature values and associated conditional variance are thus generated from which depth-to-the-isotherm maps were extracted for temperatures in the low-enthalpy range (<100 °C). The study confirms that promising thermal anomalies are mapped in the Ferrara Arc and the buried Southern Alps. These areas offer opportunities for new developments and the repurposing of depleted oil wells for district heating. Additionally, the findings highlight other areas in the Po Plain (e.g., Emilian Arc) where there exists more subtle geothermal potential for further exploration and development.

Innovation and opportunity through regulatory change

Adapting to change and seizing opportunities is a constant process for all involved in offshore energy, government and industry alike. The offshore energy sector continues to adapt approaches and adopt new ways of doing business as community expectations and the regulatory framework continue to evolve. As industry explores new frontiers in carbon capture and storage and infrastructure reuse for renewables, the historic challenges of legacy wells and decommissioning remain at the forefront of planning considerations. Recognising this changing landscape, the regulator has undergone its own evolution from investigations to drive change and enhance safety standards through to consultation best practice based on cultural awareness. This change has been driven by a refocusing of priorities and increased emphasis on where the greatest regulatory impact can be achieved. This paper outlines critical learnings from the past year – what industry is doing well and ongoing opportunities for improvement, the changes being implemented by the regulator and what they mean for industry, and what lies ahead for the offshore sector in the broader legislative and regulatory regime.

Strategic Qualitative Risk Assessment of Thousands of Legacy Wells within the Area of Review (AoR) of a Potential CO2 Storage Site

The subsurface confinement of anthropogenic carbon dioxide (CO2) demands robust risk assessment methodologies to identify potential leakage pathways. Legacy wells within the Area of Review (AoR) represent one potential leakage pathway. Robust methodologies require enormous amounts of data, which are not available for many old legacy wells. This study strategically categorizes 4386 legacy wells within the AoR of a potential CO2 storage site in the Illinois basin and identifies the high-risk wells by leveraging publicly available data—reports and well logs submitted to state regulatory agencies. Wells were categorized based on their proximity to the injection well location, depth, the mechanical integrity of well barriers, and the accessibility to these wells throughout the project lifecycle. Wells posing immediate risks were identified, guiding prioritized corrective actions and monitoring plans. Out of 4386 wells, 54 have high priority for corrective action, 10 have medium priority, and the remainder are of low priority. Case study results from the Illinois basin demonstrate the effectiveness and applicability of this approach, to assess the risk associated with legacy wells within the AoR of potential CO2 storage site, strategically categorizing over 4000 such wells despite data limitations.

Guest Editorial: Are We “Refracturing” or “Recompleting” with Mechanically Isolated Subsequent Stimulations in Organic Shales?

Numerous articles and technical papers have shown that perforating and fracture stimulating previously undrained rock in wide-cluster-spaced legacy organic shale wellbores can result in superior economics to new wells in many areas. With advances in mechanical isolation operators can seal off the narrow existing drainage intervals in legacy wells to enable stimulations to focus on “new rock.” In one reservoir-pressure-monitoring pilot well drilled by ConocoPhillips in 2016 it was observed that 85% of the lateral interval was not being drained where the original completion had 50-ft cluster spacing. The observation well was 70 ft away from the producing parent well. For wells that have relatively wide well spacings (over 600 ft), the post-stimulation total enhanced ultimate recovery (EUR) can be from three to four times the original EUR. The two most active operators doing these types of stimulations in the Eagle Ford Shale (ConocoPhillips and Devon) are primarily doing protective treatments in parent wells to avoid significant child well EUR losses from asymmetric fractures. In URTeC 3724057, Barba et al. demonstrated that when parent wells are restimulated following mechanical isolation the combined NPV10 of the post-stimulation production from the parent and the EUR preservation from the children is significantly higher than a new well’s NPV10. The first-order child wells will have asymmetric fracs running home toward the parents and stranding 40% of the reserves on their distal side if a protective refrac is not done on the parent, as was shown in SPE 213075. The second-order child wells have an average of a 20% EUR loss. Discussions with operators and presentations by upper management concerning this damage indicate that other than a few of the main players doing these subsequent stimulations, not all operators are aware of the detrimental effects of asymmetric fractures. A major operator presenting at the 2023 SUPER DUG Conference mentioned that they saw positive production increases when Bakken parent wells had fracture-driven interactions (FDIs) from offset child-well fracs. When the author asked the presenter in the Q&amp;A session if they were concerned about the EUR damage from the asymmetric fractures which resulted in these FDIs, he was clearly not aware that it was a problem. For those who might not fully grasp the nuances of challenging parent-child interactions, consider the situation of parents supporting adult children who have not yet achieved independence. The goal for these parents is to encourage self-reliance and maturity, rather than a return to a dependent lifestyle. In the context of well management, the parent-well protective refrac is also designed to enable child wells to achieve their maximum production potential. While these protective recompletions in legacy parent wells can provide a significant economic benefit, the treatments have not been accepted by all operators as a tool to significantly grow company asset value. There is little or no activity in areas where all the wells on a pad are legacy parent wells with no nearby children.

Qualitative risk assessment of legacy wells based on publicly available data for class VI well permit applications—Illinois basin case study

Carbon Capture & Storage (CCS) refers to capturing the anthropogenic carbon dioxide (CO2) at a source followed by injecting and storing it safely in the subsurface. The success of the CCS projects therefore heavily relies on how efficiently the confining zones (containment seals) prevent migration of the CO2 to the surface and/or to the underground sources of drinking water (USDW) through leakage pathways. CCS projects requires drilling of Underground Injection Control (UIC) Class VI wells for permanent storage of CO2 in subsurface. Detailed information of all the wells within the Area of Review (AoR) is needed to develop the map and tabulation components of the Class VI well permit application. This paper discusses the generic process that can be used by permit applicants to develop the dataset necessary for preparing the map and tabulation components of the Class VI permit application and perform qualitative risk assessment of all the wells within the AoR. This methodology directs the corrective action plans as well as monitoring plans to some extent. Results of the application of the newly developed methodology for wells in Illinois basin is discussed in detail. This methodology can be applied to all wells including orphaned wells, abandoned wells, active oil and gas wells, stratigraphic wells, disposal wells, etc. This methodology generalized categorization of legacy wells that will help in easier comparison of different CCS projects across the globe. The qualitative risk assessment methodology discussed in this paper is a good starting point for developing crossflow modeling.

The Implications of Ontario’s Historical Oil and Gas Drilling and Abandonment Practices for Abandoning Orphan and Legacy Wells

Oil and gas exploration in Ontario began in the mid-1800s, leading to the first oil well drilled in 1858 and the first commercial gas well drilled in 1889. These early discoveries kicked off a boom of exploration and development drilling activity, but well records were not mandatory until 1919 after the introduction of the Natural Gas Act R.S.O.1918, c. 12. The Ontario Bureau of Mines estimated 10,000 operating oil wells in the province at the turn of the 20th century, but there are only records for approximately 1,500 wells. By 1970 there were an estimated 50,000 wells drilled in the province though there are only records for 27,000 wells, indicating there may be tens of thousands of unrecorded or lost wells in southwestern Ontario. Wells that are not properly plugged are a conduit for fluid movement, including brine, natural gas, oil, and hydrogen sulphide, to move from the subsurface to the surface. Historical well abandoning regulations required wells to be plugged with inferior materials including wood, clay, and rubble. Cement was not the standard plugging material until 1964. There are orphaned and legacy wells leaking natural gas and sulphur water (groundwater containing dissolved sulphate and hydrogen sulphide) creating a risk to public safety. Orphaned and legacy wells are also a risk for subsurface energy projects including geological storage of carbon dioxide, hydrogen, and compressed air energy, because the wells may provide a pathway for injected fluids to return to the surface. This study reviews well construction, legislation, and abandonment practices in Ontario beginning in 1858 and identifies five factors impacting the plugging and abandonment of orphaned and legacy wells.Further work is required to locate unreported or lost wells and to develop new techniques to permanently plug wells to limit gas leakage, reduce greenhouse gas emissions, and improve public and environmental safety.

Monitoring casing corrosion of legacy wells using CSEM: Implications for large-scale energy and CO2 storage projects in shut-down hydrocarbon fields

Large-scale CO2 and energy storage is a mandatory part of the green shift to reduce CO2 emissions and limit consequences of climate change. Large-scale storage will require the use of shut-down depleted hydrocarbon fields to take advantage of well-characterized reservoirs and cap rocks. Thanks to extensive data from historical hydrocarbon production, the uncertainties related to storage capacity, injectivity, and containment are limited. However, legacy exploration and production infrastructure, and especially legacy wells, are the main threat for possible fluid leakage toward the surface. Such legacy wells are numerous and penetrate the full rock column. In this paper, we describe a workflow to screen and monitor legacy wells in the shut-down Frigg Field in the North Sea. By using numerical modeling of electromagnetic (EM) field propagation in one of the Frigg Field wells, we explore the complex interactions of fields, currents, and well structure in the presence of corrosion. The corrosion is implemented as a change in the electrical conductivity of the innermost steel casing at different depths along the structure. To enhance probing depth, we plug the dipole source (1 km long) into the casing at the seafloor and excite the casing as an antenna. We find that at moderate levels of corrosion, the current distribution is significantly modified with respect to the uncorroded case. This generates a signal that propagates and can be observed at the seafloor in the numerical results. Other elements of the well geometry (e.g., concentric overlapping cement casings) have their own effect on the signal. This leads the possibility of estimating the location of the corroded area within the well geometry. These results suggest that by relaxing some of the model's approximations and implementing realistic transmitters, it will be possible to evaluate and optimize controlled-source EM survey strategies for detecting and monitoring corrosion levels.

Exploration for Helium in the Phanerozoic

Almost all the helium discovered worldwide has been found by chance in the drilling for hydrocarbons. Targets were usually anticlinal structures located by seismic surveys. The association of helium and natural gas in reservoirs is purely coincidental because the source rocks for each are different—natural gas is mainly produced from diagenesis of carbon rich shale whereas Helium- 4 is derived mainly from the decay of uranium/thorium in the crust. A new geochemical exploration system for helium in the Phanerozoic is considered highly desirable by industry. The current exploration system in the Phanerozoic uses a modified petroleum system concept that has been used successfully for decades to high-grade plays and de-risk oil and gas prospects. Like a petroleum system, the helium system is identified by its source rock, reservoir, trap, seal, and migration pathways. However, this approach is expensive taking years to complete and can be a limiting factor for countries/provinces/states to develop their resources. As a precursor to ground helium/hydrogen surveys for exploration in the Phanerozoic, hyperspectral (satellite) surveys assess huge areas for their helium potential as well as any associated hydrocarbons. These areas may be even devoid of any previous exploration for hydrocarbons. This is followed with geochemical soil gas surveys of the more prospective trends to locate drilling locations. Both methods ascertain whether helium anomalies, which represent helium reservoirs at depth, are associated with hydrocarbons or nitrogen. Helium reservoirs associated with nitrogen are higher in helium content but are deeper, close to the basement. Hyperspectral and geochemical soil gas surveys are also applicable for projects that begin with helium analysis of old wells followed by seismic and drilling. Typically, exploration companies lease vast areas surrounding the legacy well, but their initial focus is on seismic in the area around the legacy well to determine the size and configuration of the helium reservoir and trap penetrated by the well and this is followed by drilling. It is not known at this point whether this reservoir is the best prospect because the helium discovered is usually associated with hydrocarbon (HC), not with nitrogen with much higher helium concentration in the lower Phanerozoic. Rarely do legacy wells penetrate deep enough to this level. Any cost-effective exploration program for helium is best accomplished by hyperspectral and follow-up geochemical soil gas surveys.

The Third Way: How BKV Turned to ‘Hybrid’ Refracs in the Barnett Shale

While refracturing has maintained a backseat role in the US shale sector, with capital overwhelmingly flowing toward new well programs, there’s been a notable exception brewing in the Barnett Shale. Last year, from within the asset that holds the very well that ignited the shale revolution, gas producer BKV Corp. announced that it had become the top refracturing operator in the US. From the end of 2021 to March of this year, covering a span of just 18 months, the operator completed an eye‑opening 369 refracs. The breath of life BKV pumped down those north Texas wells was enough to temporarily arrest the decline rate of the most mature of all shale plays. BKV reports that the Barnett refrac program has generated 371 Bcf/e of newly proved reserves with a finding and development cost of $0.79/Mcf/e. But putting these figures aside, what else stands out about the campaign is how it was done. To rejuvenate many of the vintage wellbores, the Denver‑based operator, a subsidiary of a Thailand‑based energy conglomerate, said it developed an innovative approach called the “hybrid expandable liner system.” “It is very simply a combination of both bullhead and liner methods where we attempt to minimize the downsides and maximize the positives of both,” Kevin Eichinger, a senior completions engineer for BKV, explained at a recent SPE gathering in Houston. The concept involves installing as little as a few hundred feet of expandable steel patches over a well’s original heel‑side perforations to allow for several new plug‑ and‑perforation stages. The toe‑end of the wellbore is left unlined but new perforations can be added before it is stimulated using a bullhead treatment. Eichinger, who leads the operator’s refrac candidate selection and job design efforts, described the end result as “liner‑like performance without the cost of a full liner.” The completions engineer outlined these and other details while presenting a technical paper he recently coauthored. The subject of a number of industry meetings since it was first published in June, URTeC 3855094 discusses BKV’s inaugural hybrid refracturing trial that achieved twice the average output of neighboring bullhead refracs while also besting legacy liner refrac performance achieved from operated legacy wells. The success of this first attempt paved the way for hundreds of subsequent jobs in the Barnett where the company operates or holds interest in more than 6,900 wells across 460,000 gross acres. More on BKV’s hybrid refracs follows, but worth noting is that the firm is in the midst of a “quiet period” pending the outcome of a potential move to become a publicly traded company in the US and has refrained from issuing updates about the current state of its operations in either the Barnett or the Marcellus Shale in Pennsylvania.

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.

Automated Exploration of Economical and Safe Well Trajectories in Brown Oil and Gas Fields

Summary Due to volatile and uncertain oil and gas prices, the need to reduce well planning and drilling cost is a crucial concern in the oil and gas exploration and production industry. Therefore, the focus has increased on brownfield sites for new oil and gas explorations. However, the presence of previously drilled wellbores, also known as legacy wells, in brownfield sites increases the risk of collision incidents during the drilling process. Thus, avoiding collisions is also an important objective in the well trajectory design process. Moreover, designing well trajectories is a challenging and time-consuming process. Such designs demand multiple interdependent iterations to arrive at a required cost-effective solution that meets the drillability and safety requirements. In this study, we developed a novel framework to automate the well trajectory design process, including a well trajectory optimization technique to generate safer and more economical well trajectories. The developed framework was tested on two live oil- and gasfield cases. The first field case involved designing a single well trajectory in a crowded field, and the second field case involved designing 36 well trajectories in a field that consists of 13 legacy wells. The developed framework has a high impact on reducing the well trajectory design time and drilling length of trajectories. For example, in the second field case study, the obtained solution resulted in total length savings of 2.3% compared to an existing industry-standard tool solution, and it avoided collision with 13 wells. Also, the total time taken for designing 36 collision-free optimized wells was reduced from months (as per the industry standard) to a couple of days.

Composite confining systems: Rethinking geologic seals for permanent CO2 sequestration

Permanent containment is paramount for geologic carbon sequestration. Petroleum experience proves the possibility but also creates bias—to date, carbon storage projects have used seals similar to those of producing petroleum accumulations—thick, laterally extensive, effectively impermeable layers. These work for CO2, but may not be present where needed, nor optimal for sequestration. We introduce the concept of composite confining systems, defined here as multi-layer stratigraphic systems of discontinuous barriers with no a priori requirements for continuity or minimum capillary entry pressure. We explore the concept through physical analog modeling, geologic characterization and full-scale numerical modeling. We find that barriers need only offer enough capillary entry pressure contrast to divert the flow of CO2 and that barrier frequency and barrier area are the key variables in retarding vertical migration. Data from Southern Louisiana Miocene deltaic deposits shows ∼5–15 mudstone barriers/100 m of section, with average mudstone lengths of over 1 km and aspect ratios ∼2:1, giving effective ratios of vertical to horizontal permeability (kv/kh) of ∼0.0005. Full-scale reservoir models show that these systems can completely arrest vertical migration of industrial-scale volumes of CO2 (10's of megatons) within a few 10's of meters of stratigraphic section. Unlike more conventional petroleum seals and traps, which retain CO2 in a concentrated, mobile state, composite confining systems disperse and immobilize it via migration-assisted trapping. The greatest risks to performance of composite confining systems are the same as for conventional seals–the potential shortcuts across stratigraphic barriers, e.g., legacy wells, fluid escape pipes and permeable faults that focus flow.

Mapping existing wellbore locations to compare technical risks between onshore and offshore CCS activities in Texas

AbstractCarbon dioxide capture and geologic storage (CCS; geologic sequestration) is a promising technology for reducing anthropogenic greenhouse gas emissions to the atmosphere from industrial point sources. Aspects of CCS have been investigated for over two decades, and many large‐ and small‐scale geologic storage field demonstration projects are now underway globally. Interest in offshore CCS has been increasing in recent years (e.g., European Union, Australia, Japan, and the United States). Deep geologic storage in offshore settings is analogous to onshore CCS activities in many respects (i.e., geologic and geotechnical aspects), but is distinct from previously explored seabed sediment CO2 storage) or deep marine dissolution). Given the large subsurface geologic storage volumes available in offshore settings, much discussion of offshore CCS is focused on the benefits and risks of such activity compared to onshore settings. Similar to onshore settings, existing (legacy) wells likely present the most direct migration pathway and largest risk of noncontainment in offshore settings. As part of current studies to evaluate geologic storage options in offshore settings along the Texas coast and greater Gulf of Mexico (GoM), mapping of the geographic distribution and ages of wells in a region containing coastal counties and extending 30 miles offshore Texas indicates that both well spatial density and well age decrease moving from onshore to offshore. Results suggest reduced risk of leakage owing to more rigorous and documented well completion and abandonment practices for these generally younger wells (although many are decades old). A result of decreased well density is that larger areas are available for leasing for CCS projects that avoid legacy wells altogether (&gt; 1 mile from any existing well). The one‐mile designation is used as an arbitrary convention, and while it is recognized that this is smaller than a typical area of review (AoR) for permitting, each site will have a different AoR radius for consideration. The combination of large subsurface storage volumes under control of a single landowner and reduced risks from legacy wells makes offshore CCS attractive in the GoM. © 2023 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

Commentary: Legacy wells–we need more case studies

Commentary: Legacy wells–we need more case studies

Fetch-trap Pairs: Exploring definition of carbon storage prospects to increase capacity and flexibility in areas with competing uses

As CCS grows beyond isolated first-mover projects, the question of how to identify potential storage sites (prospects) is key to siting projects amidst the constraints of neighboring storage projects, hydrocarbon fields and other considerations. To date, prospects have been defined either by the extent of a buoyant trap or by the predicted maximum extent of the CO2 or pressure plume. Both approaches have worked, but they may struggle in places like the Gulf of Mexico where complex geologic structure can invalidate simple assumptions of radial plume spread and buoyant traps are commonly unattractive due to numerous legacy well penetrations. We propose identifying prospective storage sites by fetch area (drainage cell) rather than by buoyant closure alone. Doing so offers 1) greater freedom in siting injectors to avoid surface and subsurface constraints, including legacy wells that tend to cluster on structural high; and 2) a coherent flow regime in which buoyancy drives all injected CO2 toward a common high. This strategy gives space to dissipate injection pressure and minimize the number of legacy wells needing review. It may also offer 1) better injectivity by bringing synclines and associated channel axes into play; and 2) potentially improved capacity by tapping a larger rock volume and taking advantage of migration losses.

Risk matrix for legacy wells within the Area of Review (AoR) of Carbon Capture & Storage (CCS) projects

The success of CCS depends on the capacity, injectivity, and confinement by the storage medium. Thousands of wells drilled over the past century with the intention to find the trapped oil and gas may penetrate the containment seals. These wells may provide leakage pathways for the CO2 to escape and contaminate the underground sources of drinking water (USDW) or reach the surface in the worst-case scenario. Identifying the risky wells penetrating the containment seals and predicting their current as well as future well integrity is the most challenging task when limited data is available. This paper proposes a unique methodology for risk assessment of the wells penetrating the containment seals based on the proximity of these wells from the proposed injection location, mechanical integrity, and accessibility of these wells over the lifecycle of the CCS project. This helps in identifying the wells which need immediate attention from the wells that need little to no attention. It also highlights the corrective actions necessary for the success of the CCS project as well as help estimate the approximate cost required to perform the corrective actions. This methodology focuses on all wells (producers, injectors, orphan, abandoned, water, stratigraphic, etc) while the majority of the studies found in literature focused on wells with sustained casing pressure (SCP) reports and cement bond logs (CBL). The proposed risk matrix, if applied to future CCS projects across the globe, will uniformly categorize the wells within the Area of Review (AoR).

Concurrent 21. Presentation for: The Petrel Sub-basin: a world-class CO

Presented on Thursday 19 May: Session 21 In 2021, the Australian Government announced a round of offshore greenhouse gas acreage release, including an area where research by Shell/CSIRO in 2016/2017 indicated close to 1 Gt carbon dioxide storage potential within the Mesozoic sediments of the Sandpiper, Elang and Plover Formations of the Petrel Sub-basin. The joint Shell/CSIRO study assessed key containment issues (legacy wells, potentially conductive faults, top seal extent) and storage formation connectivity. To study containment risk, CSIRO assessed a single injection well scenario and concluded that injection of up to 20 MTPA would not create geomechanical failure. Based on these findings, a ~5000 km2 area of interest southeast of the Petrel Field was proposed as suitable for injection in the Plover/Elang formations. The Shell team constructed topographical dynamic models at five potential locations. Three further models were built to simulate a base case and two end-member scenarios: (1) high permeability (leak point risk) and (2) low-pressure dissipation (top seal risk). The study showed that the development of two injector wells at one of the locations could safely and conservatively store 149 Mt, injected over a period of 30 years. Similar capacity is expected at four out of the five locations identified within the investigated area. Expansion to &gt;2 injection wells per location, additional injection into the Sandpiper Formation and expansion to the west of the initially mapped focus area all point to achievable gigatonne storage potential. The joint study significantly expanded the understanding of the storage capacity, with recommendations for further data acquisition in both greenhouse gas (GHG) permits (GHG21-1 and GHG21-2). To access the presentation click the link on the right. To read the full paper click here