Green Canyon Research Articles

The geomechanical response of the Gulf of Mexico Green Canyon 955 reservoir to gas hydrate dissociation: A model based on sediment properties with and without gas hydrate

Gas hydrate is commonly found concentrated in sand- and silt-rich reservoirs and these are thought to have great potential as an energy resource. To evaluate this potential, it is critical to understand their in-situ stress state and their behavior during production. We explore the geomechanical behavior of sandy silt sediments from a hydrate reservoir at Green Canyon GC 955, deep-water Gulf of Mexico without hydrate and compare these results to previous work on the same sandy silty sediments with hydrate present. Previous results from hydrate-bearing sediments at GC 955 using intact specimens show that the ratio of lateral to axial effective stress under uniaxial strain (K0) is strongly time-dependent and over long timescales approaches 1 (isostatic stress state). New results from sediments without hydrate using reconstituted specimens reveal that K0 is 0.51 and independent of time and stress. The reservoir without hydrate is approximately three times more compressible than with hydrate. In addition, we find that hydrate-free sediments have a normalized creep rate of Cα/Cc of about 0.028 at all stress levels, whereas hydrate bearing sediments exhibit a decrease in Cα/Cc with stress. We use these observations to present a new geomechanical model that describes how stress and porosity evolve during production of the hydrate reservoir. The key insight in our proposed model is that the sediment skeleton and gas hydrate phases share any applied external load in proportion to their relative stiffnesses. The model results predict that hydrate-bearing sediments are stiffer than gas hydrate-free sediments and that K0 reduces dramatically after gas hydrate dissociation, as is observed. At GC 955, a 5 MPa depressurization is needed to cause gas hydrate dissociation. This change in pore pressure increases the vertical and horizontal effective stresses from 3.8 to 8.8 MPa and 3.8–4.4 MPa, respectively. The dramatic vertical effective stress increase will cause significant compaction (7%) and perturb stresses near the wellbore. These experimental observations and the load-sharing model presented have the potential to underpin a new generation of hydrate reservoir simulation models, which may drive more effective production approaches.

CO2 Storage Site Analysis, Screening, and Resource Estimation for Cenozoic Offshore Reservoirs in the Central Gulf of Mexico

The storage potential of hydrocarbon reservoirs in the central Gulf of Mexico (GOM) makes future development of CO2 storage projects in those areas promising for secure, large-scale, and long-term storage purposes. Focusing on the producing and depleted hydrocarbon fields in the continental slope of the central GOM, this paper analyzed, assessed, and screened the producing sands and evaluated their CO2 storage potential. A live interactive CO2 storage site screening system was built in the SAS® Viya system with a broad range of screening criteria combined from published studies. This offers the users a real-time assessment of the storage sites and enables them to adjust the filters and visualize the results to determine the most suitable filter range. The CO2 storage resources of the sands were estimated using a volumetric equation and the correlation developed by the National Energy Technology Laboratory (NETL). The results of this study indicate that 1.05 gigatons of CO2 storage resources are available in the developed reservoirs at the upper slope area of the central GOM. The Mississippi Canyon and Green Canyon protraction areas contain the fields with the largest storage resources.

Salt welding during canopy advance and shortening in the Green Canyon area, northern Gulf of Mexico

Salt welding during canopy advance and shortening in the Green Canyon area, northern Gulf of Mexico

BP’s Argos FPU Offers Fresh Lessons for the Future of Deepwater GOM Projects

Tipping the scales at well over 60,000 tons, BP’s Argos platform is a giant among giants in the deepwater US Gulf of Mexico (GOM). Standing 27 stories tall, the platform has a deck the length and width of an American football field and is one of BP’s largest in the region. One-time KBR subsidiary GVA designed the semisubmersible, the centerpiece of the supermajor’s $9 billion Mad Dog II project built to unlock additional production potential of the Miocene-aged reservoirs estimated to hold more than 5 billion bbl of oil in place. But that wasn’t always the plan. Over a decade ago, BP’s Mad Dog II looked quite different. On paper, the producer was looking at an all-subsea development tied back to another large spar platform—dubbed Big Dog—to host the additional reserves. The development plan envisioned a massive truss spar. Its topsides would need to be installed via three separate offshore lifts then fully integrated at the field site. Any offshore heavy lift is an execution risk. In 1998, an accident while lifting the south module onto Texaco’s Petronius compliant tower in the GOM resulted in the loss of that section of the topsides and delayed the project for a year and a half. That module weighed 3,600 tons. Another hesitation for BP? The price tag. All-in, the spar-based Mad Dog II solution was estimated to cost around $19 billion. That included 30-plus wells. Ultimately, the spar concept was scrapped, and BP moved back to square one and a blank sheet of paper. “The reserves were there,” said Chris Ruthven, project general manager, Mad Dog II. “We knew the reserves were there. In fact, ironically, the team developed the field with the smallest of the four big platforms that BP did back at that point in time: Thunder Horse, Holstein, Atlantis, and Mad Dog. It was the smallest, but ultimately, it was the second-biggest field. It turned out to be huge. All that appraisal showed we’ve got a lot of reserves. So, we went back and went with an analog to Atlantis. Atlantis was seen as a good fit requiring much less offshore integration work. Operations loved the asset, and it was a very safe design. We landed on that concept, and we tried to keep it almost pretty much the same in terms of the overall layout of the facility, but it’s a little bit bigger footprint.” Mad Dog proper was discovered in 1998 via an exploration well in over 6,100 ft of water located in Green Canyon Block 826. The well was drilled to a measured depth of 22,410 ft and encountered around 215 ft of hydrocarbon-bearing Miocene reservoirs. The discovery was followed by a 1999 well drilled to a total depth of 22,410 ft and a further successful appraisal well in February 2000. Mad Dog, covering Green Canyon blocks 825, 826, and 782, was sanctioned as a spar-based development in 2002. The project came online in early 2005.

The Viscoplastic Behavior of Natural Hydrate‐Bearing Sandy‐Silts Under Uniaxial Strain Compression (K0 Loading)

AbstractThe in‐situ stress state and geomechanical properties of hydrate‐bearing sediments impact hydrate formation and gas production strategies. We explore the uniaxial strain compression and stress evolution of natural hydrate‐bearing sandy‐silts from Green Canyon Block 955 in the deep‐water Gulf of Mexico. We performed constant rate of strain uniaxial strain experiments, interrupted by periods where we held the axial stress constant, to explore the vertical deformation and the evolution of the ratio of lateral to axial effective stress (K0) with time. The hydrate‐bearing sandy‐silt is stiffer and has a larger K0 than the equivalent hydrate‐free sediment upon loading. During stress holds, the void ratio decreases sigmoidally with the log of time, and K0 converges to isotropic conditions. We interpret that during loading, the hydrate bears the load and deforms. With time, the hydrate redistributes the load and K0 increases. We used a viscoelastic model to describe the behavior. The model accurately captures deformation and K0 trends but does not reproduce all the complex interactions of the hydrate with the porous skeleton. We anticipate that viscous effects within hydrate sediments will impact reservoir compression and stresses during production (hours to days), result in isotropic stress state over geological timescales, and explain the creeping movement in submarine landslides.

Toward generalized models for machine-learning-assisted salt interpretation in the Gulf of Mexico

Interpreting salt bodies in the Gulf of Mexico (GoM) can be complex due to various factors affecting the accuracy of automated techniques. Variability of salt structures, seismic acquisition parameters, and imaging algorithms can impact the resulting seismic image. These differences can result in variations in seismic resolution and texture, making it challenging to develop automated interpretation techniques that are accurate and reliable for identifying salt bodies in the GoM. However, using seismic images with similar acquisition parameters and processing methods minimizes these differences and makes machine-learning (ML) models applicable. Utilizing nine data sets from the eastern GoM, a nine-fold cross-validation technique was applied to measure the generalization performance of the ML model. This method involves using one data set as the test set and the remaining eight for training and repeating the process for all subsets. We further applied an ensemble of the nine models to predict salt on a new unseen survey in Green Canyon. The study aimed to illustrate how salt variability and morphology in the GoM can impact the ability of the ML algorithm to predict salt bodies on unseen data.

Salt Diapir‐Driven Recycling of Gas Hydrate

AbstractBy harnessing both hypothetical, synthetic basin and gas hydrate (GH) system models and real‐world models of well‐studied salt diapir‐associated GH sites at Green Canyon (Gulf of Mexico) and Blake Ridge (U.S. Atlantic coast), we propose and demonstrate salt movement (and in particular, diapirism) to be a new mechanism for the recycling of marine GH. At Green Canyon, for example, we show that by considering this newly proposed diapir‐driven recycling mechanism in conjunction with previously proposed lithological control on sandy‐reservoir‐hosted hydrate at the base of the GH stability zone (BGHSZ; ∼bottom‐simulating reflector, BSR), modeled GH saturations match drilling data. Overall, salt diapir movement‐induced GH recycling provides a temperature‐driven mechanism by which GH saturations at the BGHSZ may reach >90 vol. % and by which GH volumes near and free gas volumes beneath the BGHSZ may be increased significantly through time. Interestingly, comparison of salt diapir‐driven recycling and sediment burial‐driven recycling scenarios suggests notably higher rates of recycling via diapir‐driven versus burial‐driven processes. Our results suggest that GH and associated free gas accumulations above salt diapir crests represent particularly attractive targets for unconventional and conventional hydrocarbon resource exploration and for scientific and academic drilling expeditions aimed at exploiting GH systems. Salt basins containing GH systems—including passive margin basins of the Gulf of Mexico, southeastern Brazil, and southwestern Africa—are therefore compelling localities for studying salt‐driven GH recycling and for salt diapir‐associated natural gas exploration.

Uncovering the temporal carbon isotope (δ13C) heterogeneity in seep carbonates: a case study from Green Canyon, northern Gulf of Mexico

Authigenic carbonates that form at hydrocarbon seeps, known as seep carbonates, are direct records of past fluid flow close to the seafloor. Stable carbon isotopes of seep carbonates (δ13Ccarb) have been widely used as a proxy for determining fluid sources and seepage mode. Although the spatial heterogeneity of δ13C in seep carbonates is increasingly understood, the temporal heterogeneity of δ13C in seep carbonates is not well studied. In this study, we report δ13C values of different components (clasts, matrix, and pore-filling cements) for 124 subsamples drilled across an authigenic carbonate block from Green Canyon block 140 (GC140) of the northern Gulf of Mexico continental slope. High-Mg calcite is the dominant mineral regardless the types of components. The δ13Ccarb values range from −39.6‰ to 3.6‰, indicating multiple dissolved inorganic carbon (DIC) sources that include methane carbon (13C-depleted), seawater DIC, and residual CO2 from methanogenesis (13C-enriched). Specifically, the clasts show large variability in δ13C values (−39.6‰ to 2.3‰; mean: −27.6‰, n = 71), demonstrating the dominance of methane-derived fluids during formation at the initial seepage stage. The δ13C values of the matrix vary between −29.4‰ and 3.4‰ (mean: −11.6‰, n = 21). The carbon isotopes of pore-filling cements that formed most recently vary narrowly, with δ13C values of −3.2‰ to 3.6‰ (mean: 1.7‰, n = 28). Isotopic variations within individual samples were observed in seep carbonate. However, common trends occur across components of carbonates that formed during different seepage stages. This suggests that the temporal evolution of local fluid sources may play an important role in determining carbonate isotope geochemistry. Studies regarding seeps must take into account the highly variable fluids that leave their geochemical imprints on the seep carbonate.

Gas Hydrates Reserve Characterization Using Thermo-Hydro-Mechanical Numerical Simulation: A Case Study of Green Canyon 955, Gulf of Mexico

The Gulf of Mexico is a widely explored and producing region for offshore oil and gas resources, with significant submarine methane hydrates. Estimates of hydrate saturation and distribution rely on drilling expeditions and seismic surveys that tend to provide either large-scale estimates or highly localized well data. In this study, hydrate reserve characterization is done using numerical simulation at Green Canyon block 955 (GC955). In addition, coupled thermo-hydro-mechanical (THM) simulation results show that hydrate saturation and geobody distribution are determined by the thermodynamic conditions as well as reservoir structures, stratigraphic differences, and permeability differences. Hydrate formation due to upflow of free gas and dissociation due to gas production and oceanic temperature rise due to climate change are simulated. The abundance of free gas under the hydrate stability zone and favorable pressure and temperature meant little hydrate was depleted from the reservoir. Furthermore, the maximum displacement due to warming reached 0.5 m in 100 years and 4.2 m in 180 days based on a simulation of constant production of methane gas. The displacement direction and magnitude suggest that there is little possibility of slope failure. Therefore, the GC955 site studied in this paper can be considered a favorable site for potential hydrate exploitation.

Surveillance Optimizes Development Plan for a Deepwater Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210274, “Effective Use of Surveillance To Optimize the Development Plan for a Deepwater Reservoir,” by Cengiz Satik, SPE, Matthew Burgess, SPE, and Matthew Carter, Chevron, et al. The paper has not been peer reviewed. _ A three-phase strategy was adopted for a deepwater reservoir development as a result of large uncertainties associated with fault compartmentalization and aquifer support. The first phase began with primary production from several wells, while water injection was implemented a few years later as a second phase. The third and final phase involved infills. Data collected during drilling were used to improve reservoir characterization. The complete paper describes how a surveillance, analysis, and optimization plan resolved key subsurface uncertainties and optimized the development plan and presents lessons learned and best practices. Introduction The field is in the central Gulf of Mexico Green Canyon. It produces from a series of stacked subsalt reservoirs consisting mainly of lower-slope to basin-floor turbidite sands. Uncertainty in flow behavior exists in prospective areas near low-confidence faults, affecting well performance and ultimate recovery predictions. To improve reservoir characterization and enhance field-performance predictions, a full-factorial 3D static Earth model was built by integrating well, surveillance, and seismic data. Dynamic simulation was used to help calibrate the well and field historical performance, forecast future recovery, and highlight and test potential opportunities. Despite achieving acceptable history-matched simulation models, specific development scenarios presented large recovery uncertainties and varying economic outcomes. In this work, results from reservoir surveillance modeling and execution were used to narrow the range of recovery uncertainty and improve field-development decisions. Dynamic reservoir-surveillance techniques, such as interference and pulse testing, used in this study provided key evidence that reduced fault compartmentalization uncertainty significantly and eliminated the need for a costly infill well to recover remaining resources. Furthermore, increased confidence in recent seismic-imaging enhancements has since corroborated these results. Opportunity The reservoir is the deepest producing reservoir in the field. It consists of two distinct and vertically separated zones. Southwest of the historical production from Reservoir 1, existing fault interpretation from seismic imaging placed three faults (Faults 1, 2, and 3), creating several compartments within the area (Fig. 1). An infill drilling program was progressed to drain the resources from these compartments. Well 1 was completed only within Zone 1 (upper zone). As shown in Fig. 1, Well 2 was a new drill between the interpreted Faults 2 and 3. It was completed as an intelligent well perforated along both zones of the reservoir. The length and transmissibility of all three faults, as well as the reservoir heterogeneity within the area, were highly uncertain. Consequently, previous development plans placed a potential infill well between Fault Blocks 1 and 2 to drain the volume within the compartment bounded by Faults 1 and 2. However, reservoir simulation studies indicated that recoverable resources from this future infill well were highly dependent on the sealing nature of Faults 1 and 2.

E&P Notes (September 2022)

E&P Notes (September 2022)

E&P Notes (June 2022)

E&P Notes (June 2022)

Using x-ray computed tomography to estimate hydrate saturation in sediment cores from Green Canyon 955, northern Gulf of Mexico

Quantifying the amount of gas hydrate in a reservoir provides valuable insight on gas hydrates’ potential as a resource and their contribution to the global carbon cycle. We develop a new method to estimate hydrate saturation from density-sensitive X-ray computed tomography (XCT) scans of pressure cores from northern Gulf of Mexico (Green Canyon Block 955). While several studies have used XCT to quantify gas hydrate in the fractures of fine-grained sediments, our study is the one of the few to use XCT for coarse-grained (sand and silt) reservoirs. We calibrate our new method with grain density and quantitative degassing measurements from the same intervals. This paper uses the density difference between gas hydrate (0.924 g/cm3) and porewater brine (1.035 g/cm3) and assume these changes linearly affect the XCT measurements allowing for estimates of hydrate saturation. Overall, the XCT calculations agree with the hydrate saturation from quantitative degassing. For example, in core H005-3FB-3, quantitative degassing indicated a hydrate saturation of 88 ±33.5%, while the XCT calculations yielded a 90 ±4 4.8% saturation. These results are encouraging as they suggest that XCT analysis has the potential to nondestructively estimate hydrate saturation.

Occurrence of high-saturation gas hydrate in a fault-compartmentalized anticline and the importance of seal, Green Canyon, abyssal northern Gulf of Mexico

Occurrence of high-saturation gas hydrate in a fault-compartmentalized anticline and the importance of seal, Green Canyon, abyssal northern Gulf of Mexico

Integrated geochemical approach to determine the source of methane in gas hydrate from Green Canyon Block 955 in the Gulf of Mexico

Massive volumes of gas are sequestered within gas hydrate in subsurface marine sediments in the Gulf of Mexico. Methane associated with gas hydrate is a potentially important economic resource and a significant reservoir of carbon within the global carbon cycle. Nevertheless, uncertainties remain about the genetic source (e.g., microbial, thermogenic) and possible migration history of natural gas incorporated into hydrate. Previous studies have primarily used the hydrocarbon molecular (CH4/C2H6+) and isotopic (δ13C-CH4, δ2H-CH4) compositions of natural gas to address these uncertainties. However, hydrocarbon tracers are altered by mixing, oxidation, secondary methanogenesis, or fluid migration, which presents challenges when deciphering the mechanisms responsible for methane formation and accumulation. To evaluate the genetic source of natural gases from Green Canyon Block 955 (GC 955), east of the Sigsbee escarpment, we collected and analyzed samples from the first pressurized hydrate-bearing sediment cores collected from a coarse-grained hydrate reservoir in the Gulf of Mexico. Gas samples were analyzed for hydrocarbon (C1- C5), major gas (e.g., N2, CO2), and noble gas (He-Xe) abundance and isotopic (e.g., δ13C-CH4, δ2H-CH4, δ13C-CO2, δ15N-N2, 3He/4He, 4He/20Ne) compositions. We determined that natural gas in hydrates from this location are predominantly of primary microbial origin (conservatively at least 76%) and are formed by the hydrogenotrophic (CO2 reduction) methanogenesis pathway. We also note increased thermogenic proportions (~6%) in a hydrate-bearing layer below the main hydrate-bearing interval (separated by a 5 m water-bearing layer). Our results suggest that microbial methane may be abundant below the base of gas hydrate stability at GC 955.

Pore structure of sediments from Green Canyon 955 determined by mercury intrusion

Pore structure of sediments from Green Canyon 955 determined by mercury intrusion

Permeability of methane hydrate-bearing sandy silts in the deep-water Gulf of Mexico (Green Canyon Block 955)

Permeability of methane hydrate-bearing sandy silts in the deep-water Gulf of Mexico (Green Canyon Block 955)

Methane migration mechanisms for the Green Canyon Block 955 gas hydrate reservoir, northern Gulf of Mexico

In marine continental margins, high saturations of natural gas hydrate are observed within the gas hydrate stability zone, but the gas migration pathways to the hydrate reservoir are not often clear. We focus on a site in Green Canyon Block 955 (GC 955) in the Gulf of Mexico, where gas hydrate occurs in a 35 m-thick reservoir with saturations of 79-93% in numerous centimeter- to decimeter-thick sandy silt layers and little to no gas hydrate in the interbedded cm to decimeter-thick clayey silt layers. Different datasets (well logging, coring, and seismic data) suggest different types of potential methane migration mechanisms. For example, relatively high particulate organic carbon content in the reservoir and the microbial methane source indicated by gas chromatography and methane isotopes suggest gas might be made locally and migration could occur through dissolved methane sources or water advection. In contrast, the visible deeply rooted faults intersecting the gas hydrate reservoir and the gas pockets adjacent to the faults on seismic data suggest that free gas may migrate directly into the reservoir. We tested three different mechanisms to form gas hydrate at GC 955: short-range methane diffusion, short-range methane diffusion coupled with upward water advection, and free gas flow. The 1-D and 2-D numerical models show that both the short-range migration and the upward water advection are not enough to form high saturations gas hydrate at GC 955, and that free gas flow is required to form the high saturations of gas hydrate observed at GC 955.

Comprehensive pressure core analysis for hydrate-bearing sediments from Gulf of Mexico Green Canyon Block 955, including assessments of geomechanical viscous behavior and nuclear magnetic resonance permeability

Comprehensive pressure core analysis for hydrate-bearing sediments from Gulf of Mexico Green Canyon Block 955, including assessments of geomechanical viscous behavior and nuclear magnetic resonance permeability

Gas hydrates in Green Canyon Block 955, deep-water Gulf of Mexico: Part II, Insights and future challenges

Gas hydrates in Green Canyon Block 955, deep-water Gulf of Mexico: Part II, Insights and future challenges