Deepwater Gulf Of Mexico Research Articles

Coupling reservoir depletion and geomechanics to assess risks during post-blowout well capping: Case study on Macondo

Reservoir depletion can be consequential to wellbore integrity after a blowout, especially offshore. A prolonged post-blowout discharge extends reservoir depletion. “Underground blowouts” (tensile-fracture initiations) occurring after well capping, or shear-driven slow slippage of naturally-occurring pre-existing faults (PEFs) in the near-well vicinity, can compromise post-blowout wellbore integrity. Upward propagation of the initiated tensile fractures may trigger seafloor broaching by reservoir hydrocarbons.This study examines reservoir depletion analytically, evaluating associated geomechanical implications on the in-situ reservoir conditions and assessing the likelihood of tensile-fracture initiation (oriented longitudinally or transversely-to-the-wellbore) during post-blowout-well-capping operations, in addition to shear-driven slow slippage along PEFs in the near-well vicinity. A set of calculational procedures and thinking sequences are presented, necessary for encompassing the primary effects of post-blowout reservoir depletion on the in-situ stress state and the limits of tensile and shear failures that could aid in the appropriate blowout-contingency decision-making.Our novel, physics-based scheme (analytical-coupling approach) is applied to parameters from the MC 252–1 “Macondo Well” blowout from April 20, 2010 and the targeted M56 oil reservoir in deepwater Gulf of Mexico (GoM). The reservoir rock is modeled as a porous-permeable medium, considering fluid infiltration to-and-from the pressurized wellbore. The likelihood of an underground blowout correlates with the shut-in wellbore pressure buildup, after successful well capping.Elevated reservoir depletion via higher post-blowout-discharge flowrates and longer post-blowout-discharge periods (in terms of time duration) are shown to reduce the shut-in wellbore pressure buildup against time following well capping. The “critical discharge flowrate,” an established predictive indicator for underground blowouts following shut-in of an installed subsea-capping stack (SCS) is employed, using data from the post-blowout-discharge period, suggesting underground blowouts to be highly-unlikely for the set of parameters assessed. Finally, the Mohr-Coulomb criterion indicates that shear-driven slow slippage along PEFs in the near-well vicinity is also unlikely, considering the Macondo Well's bottomhole-wellbore-pressure history in the aftermath of the blowout.

Heavy Mineral and Zircon Age Constraints on Provenance of Cenozoic Sandstones in the Gulf of Mexico Subsurface

Combined heavy mineral analysis and detrital zircon geochronology have enabled us to track detritus supplied by the ancestral river systems draining the North American continent into the deep subsurface of the Gulf of Mexico, in both the coastal plain and the offshore deep water areas. During deposition of the Paleocene–Eocene Wilcox Group, sandstones in the western part of the area are interpreted as the products of the Rosita system derived via paleo-Rio Grande material, with a large component of sediment shed from the Western Cordillera. By contrast, samples from wells further east have high proportions of zircons derived from the Yavapai-Mazatzal Province and are attributed to the Rockdale system with sediment fed predominantly by the paleo-Colorado or paleo-Colorado-Brazos. There is evidence that sediment from the Rosita system occasionally extended into the central Gulf of Mexico, and, likewise, data indicate that the Rockdale system sporadically supplied sediment to the western part of the basin. During the Late Eocene of the central Gulf of Mexico (Yegua Formation) there was a distinct shift in provenance. The earlier Yegua sandstones have a large Grenville zircon component and are most likely to have had a paleo-Mississippi origin, whereas the later Yegua sandstones are dominated by zircons of Western Cordilleran origin, similar to Wilcox sandstones fed by the Rosita system via the paleo-Rio Grande. The switch from paleo-Mississippi to paleo-Rio Grande sourcing implies there was a major reorganisation of drainage patterns during the Late Eocene. Miocene sandstones in the deepwater Gulf of Mexico were principally sourced from the paleo-Mississippi, although the paleo-Red River is inferred to have contributed to the more westerly-located wells.

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.

Full Elastic Imaging – Shenzi Field, Deep-Water Gulf of Mexico

Full Elastic Imaging – Shenzi Field, Deep-Water Gulf of Mexico

Enhanced Reservoir Description via Areal Data Integration and Reservoir Fluid Geodynamics: A Case Study From Deepwater Gulf of Mexico

Accurate reservoir characterization is vital for effective decisions made throughout the life cycle of an oilfield reservoir, including management and development. Of all the components of reservoir description, hydraulic connectivity carries the highest amount of uncertainty, where inaccurate connectivity evaluation often results in production underperformance. Shortcomings are faced when applying conventional approaches of connectivity assessment. Seismic surveys are not always sufficient to evaluate lateral connectivity as detected faults can be transmissive or partially transmissive, while some faults are below the detection limits of seismic amplitude measurements. Vertical connectivity represents another uncertainty, where pressure measurements and well logs are often either unable to detect the baffles along oil columns or cannot assess whether detected baffles are relevant seals or flow diverters. Although conventional downhole fluid analysis (DFA) workflows have proven effective in delineating reservoir connectivity, enough DFA data are not always available, and with added complexity, uncertainties arise. Additionally, while equilibrated asphaltene gradients, measured through DFA probes, imply connectivity, ongoing reservoir fluid geodynamics (RFG) processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. Thus, a comprehensive assessment approach, that utilizes all available data streams, is needed to overcome the significant spatial complexity associated with moderately and heavily faulted reservoirs. In this paper, we employed our recently introduced interpretation workflow to evaluate the connectivity of a heavily faulted reservoir in the deepwater Gulf of Mexico. The field was divided into five investigation areas penetrated by 12 wells. Areal downhole fluid analysis (ADFA) was applied to assess local connectivity leading to reservoir-scale connectivity. Through integrating fluid/dynamic and rock/static data, each data type provided insights that were pieced together to enhance consistency and reduce uncertainty. Analyzed data included pressure-volume-temperature (PVT) reports, pressure surveys, well logs, and geochemistry. The study resulted in a verifiable connectivity description where faults, previously regarded as sealing, were classified into sealing or partially transmissive faults; unresolved faults were detected. Fault-block migration was detected, and fault throw was estimated; asphaltenes behavior was used to deduce original field structures prior to faulting. We also examined RFG processes to investigate oil biodegradation, where an asphaltene clustering trend was observed, causing high oil viscosities toward the bottom of one sandstone. A correlation was then derived and successfully implemented to estimate oil viscosity.

Age-dating and assumptions testing of 226Ra and 228Ra decay series applied to barite chimneys and mud volcanoes in deepwater Gulf of Mexico

A chronological framework of ocean-based methane emissions is a prerequisite to identify the factors controlling the flux and duration of gas venting into the atmosphere.Here we report the results of a study of ubiquitous barite chimneys and barite-bearing mud volcanoes documented in association with methane seeps and gas hydrates at mid-bathyal depths in the Gulf of Mexico.The barites exhibit anomalously high 226Ra and 228Ra activities, orphans in the 238U/232Th decay chains, and are well suited for the application of 210Pb/226Ra and 228Th/228Ra dating methods. In order to account for the interference of impurities with the accuracy of the dates, gamma counts from paired raw and purified aliquots were evaluated. Chimneys yield a mean 228Th/228Ra age of 1.60 ± 0.25 yr (n = 16) and consistently younger 210Pb/226Ra ages. The biased 210Pb/226Ra ages are attributed to poor 210Pb counting efficiency, young chimneys with little 210Pb ingrowth and possibly an open system. Rapid vertical growth rates of 11.4 and 12.8 cm/yr established from 228Th/228Ra ages are comparable to barite chimney estimates from hydrothermal settings.In general mud volcanoes are distinguished from the chimneys by absence of 228Ra and 228Th and high 210Pb/226Ra ratios, occasionally >1 in the raw subsamples. A positive relation between 210Pb/226Ra and the amount of pyrite in the samples supports the contention that PbS, co-precipitated with pyrite in H2S-rich pore fluids, acts as the principal scavenger of external 210Pb resulting from decay of 222Rn in the pore fluids. The mud volcanoes 210Pb/226Ra assays yield consistent ages with a mean of 17.4 ± 1.8 yr (n = 9) after removal of the pyrite. The general absence of 228Ra and 228Th in the mud volcanoes, contrasting to their abundance in the chimneys, is attributed to the age difference between the barite geomorphic forms.The (228Ra/226Ra)o initial activities in the chimneys, representing the ratios in the fluids at the time of barite deposition, exhibit statistically distinct values of 1.084 ± 0.015 (n = 28) and 0.752 ± 0.023 (n = 4) at the two sampling sites separated by a 265 km stretch. These (228Ra/226Ra)o values match the range of oil-field brine values from deep siliciclastic reservoirs in the US Gulf Coast. The fluids maximum migration time from the source to the seafloor is estimated to be <20 yr on the basis of 228Ra presence in the chimneys. The assessment based on the radiometric ages supports the notion that barite deposition in the Gulf of Mexico is a relatively recent event.

Wireline Logging Operation Uses Water-Based Drilling Fluid in HP/HT Gulf of Mexico Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210021, “Wireline Logging in High-Overbalance, High-Pressure/High-Temperature Deepwater Gulf of Mexico Well With Water-Based Reservoir Drilling Fluid,” by Martin Tjioe, Jeremy McCaslin, and Jonathan J. Brege, SPE, Shell, et al. The paper has not been peer reviewed. _ Openhole wireline logging, because of its lower overpull capacity relative to logging while drilling, is subject to increased stuck-tool risk. The risk increases in higher-overbalance environments typical for depleted reservoirs, but other aspects of sticking risk can be managed. The complete paper describes the measures taken in an openhole wireline-logging operation in a deepwater Gulf of Mexico (GOM) well under nearly 7,000-psi overbalance in a high-pressure/high-temperature (HP/HT) slimhole environment using water-based reservoir drilling fluid (RDF) to achieve an efficient logging operation without incurring lost time attributed to conveyance-related issues. Introduction The wireline data-acquisition program was planned for an injector well in the deepwater GOM development field. The goal of the well was to maintain reservoir pressure through waterflooding, maximize recovery, and appraise the downdip portion of the fault block. The target was an aeolian sandstone reservoir at a depth of approximately 25,500 ft total vertical depth subsea featuring 19% porosity and permeability in the tens-of-millidarcy range. The reservoir had depletion of 6,850 psi; the well penetrated 174 ft of the reservoir with a hole size of 7 in. and a deviation of 25°. The injector used an openhole stand-alone-screen completion concept. Water-based RDF was used so that filter-cake material could be removed using a breaker fluid to enable matrix injection. Using a 13.5-lbm/gal mud weight, the wireline operation was performed under a downhole pressure of 17,900 psi (overbalance of 6,950 psi). The maximum temperature recorded during wireline was 320°F. Wireline Data-Acquisition Program The wireline program’s objectives were to acquire safely a profile of pressures and mobilities to identify depletion boundaries and to inform completion operations and acquire temperature data to infer the static formation temperature. During the planning phase, the well was classified as highly challenging, with a high risk of differential sticking based on the analog wireline jobs in the field. The well of interest penetrated the reservoir with the highest depletion encountered in the field at the time; because of its downdip location, it also had one of the higher downhole temperatures in the field. Several learnings from analog wells that are further detailed in the complete paper included the following: - Necessity of good hole cleaning - Reduction of toolstring length - Necessity of a water-based RDF with good fluid properties

Can elastic waveform inversion benefit from inverting multicomponent data?

Waveform inversion aims to retrieve high-resolution earth parameter volumes. Due to its high computational cost, acoustic approaches using low to mid seismic data frequencies are often applied in velocity model building. However, in the presence of large parameter contrasts, an elastic formulation should be preferred due to wave interferences that limit the applicability of phase- and kinematics-only approaches. The benefits of elastic waveform inversion have been demonstrated with inversion of hydrophone data in marine environments. Here, we extend the approach to inversion of the vertical geophone component. We propose a weighted cost function in the waveform inversion algorithm to jointly invert multicomponent data sets, and we compare the results to the inversion of single-component data. For this study, we use an ocean-bottom-node data set from the deepwater Gulf of Mexico around a salt dome. We show that slightly different velocity models, reverse time migration images, and angle gathers are retrieved when using hydrophone or vertical geophone data, further improving either the shallow or deeper sediments. The joint inversion combines the improvements brought by the single-component inversions. Though it doubles the cost, joint elastic waveform inversion of hydrophone and vertical geophone data can help velocity model building around salt bodies.

Hydrate-bearing sands in the Terrebonne Basin record the transition from ponded deposition to bypass in the deep-water Gulf of Mexico

We integrated well and seismic data to interpret the stratigraphic architecture and the paleogeographic evolution of two hydrate-bearing sand reservoirs in the Terrebonne Basin in the deep-water Gulf of Mexico. These sands were deposited during the final stage of ponded fill within the Terrebonne Basin. The Green sand filled the final accommodation in the basin as a perched apron; it was formed coincidentally with downstream erosion and sediment bypass which cut through a canyon formed on the southeastern edge of the basin. Subsequently, a low energy turbidite channel continued to bypass sediment through the basin and aggrade. The Orange sand was then deposited as a second perched apron and it was once again incised by the low energy turbidite channel. The Green and Orange sands are regional sheet sands that extend and thicken deep into the Terrebonne Basin. They provide a connected regional aquifer that captured and focused gas migration to the crest of the structure where hydrate was formed. These sands were formed by large, unconfined, turbidity flows. We envision that they will be composed of coarser grained deposits relative to previously explored hydrate reservoirs within levee deposits. As such, they have the potential to be relatively coarse grained and hence have higher permeability: a condition favorable to production of hydrate deposits.

Gulf of Mexico Operators Transition to Faster, Cheaper Developments as Production Decrease Looms

The US Gulf of Mexico (GOM) has long been a sound investment opportunity for operators looking for world-class oil fields, stable government regimes, and predictable regulatory requirements. Since the 1980s, the region’s deeper waters have been populated by fresh infrastructure as commercial discoveries were made, appraised, and developed. Today, more than two dozen floating production platforms and miles of export and transport pipelines populate the area, with more on the way as producers continue successful exploration programs in the area. There have been nearly 90,000 offshore wells drilled in the GOM to date. The GOM arena has experienced a few bumps in the road over the past few years due to both COVID-19 and the challenges to the most recent lease sale that was revoked, then later reinstated. While GOM oil production dipped from its peak in 2019 due in part to the global pandemic, the area is still an appealing region for operators. Operators used that period to focus on short-cycle and low‑cost recompletions, infills, and tiebacks rather than larger, capital‑intensive projects. According to a report released by the US Bureau of Energy Management (BOEM), GOM production is expected to experience growth and multiple record years of total oil production, despite off‑trend production levels in 2020 and 2021. Gas production is expected to experience moderate increases but is not expected to rebound near previous highs. The growth in annual oil production predicted in the following years is supported by a strong project queue as deferred projects will now be executed. From 2022 through 2024, oil production is forecast to have strong growth, followed by a relative plateau (until 2027) and a gradual decline through 2031, the end of the forecast period (Fig. 1). Around 70% of new GOM production in 2023 is expected to come from just three projects: BP’s Argos, Shell’s Vito, and Murphy’s King’s Quay. The predicted decline may be due in part to the number of new wells being drilled in the area. The well count for the GOM in general had a decade’s peak back in 2018; however, the count has trended down ever since. According to analysts at Enverus, industry averaged almost 30 ultradeepwater wells per quarter during 2018 and 2019. Last year, that number was around 15. With fewer wells come fewer discovery opportunities. With fewer discoveries backfilling the queue of potential developments, the GOM could be headed for a lull in new project commitments. Additionally, Wood Mackenzie research found that net discovered resource by company in the GOM fell from more than 1 billion bbl in 2017 to around 250 million bbl in 2021. Research from Rystad Energy showed just two deepwater GOM hub-based developments received a green light in 2021 (Shenandoah and Whale), while so far in 2022, only one (Salamanca) has been approved (Fig. 2). Counter to that, several subsea tiebacks are in the queue. While these historically represent smaller production volumes, they also represent significantly reduced cycle times from inception to first oil.

Wellbore Integrity After a Blowout: Stress Evolution Within the Casing-Cement Sheath-Rock Formation System

A robust evaluation of the casing-cement sheath-rock formation system is foundational in ensuring wellbore integrity throughout a well's lifecycle. Analytical theory for a multi-layer, thick-walled cylinder is used to evaluate the aggregate stress distributions within the casing-cement sheath-rock formation system, honoring boundary conditions of radial stress and displacement continuity. These stress distributions are adjusted for scenarios that a well may experience in its lifetime. Each layer of the casing-cement sheath-rock formation system is evaluated separately against various possible mechanical failure mechanisms, all of which can compromise wellbore integrity.A blowout scenario after a mismanaged loss-of-well-control situation induces high stress loads in the casing-cement sheath-rock formation system, with the wellbore pressure rapidly decreasing during post-blowout discharge, followed by a rapid increase following successful well capping. Casing and cement sheath failures can expose the surrounding rock formation to the pressurized fluid inside the wellbore, risking hydrocarbons broaching the surface, or the seafloor. The aggregate stress distribution model is applied on a case study performed using parameters from the MC 252–1 “Macondo Well” blowout from April 20, 2010 in the deepwater Gulf of Mexico. The stress evolution suggests stability against mechanical failure mechanisms within the casing (collapse/burst and tensile/compressive), cement-sheath (inner or outer debonding, and shear cracking), and rock-formation layers (longitudinal or transverse tensile fracture initiation, along with shear-slippage along pre-existing faults in the near-well vicinity), throughout the blowout aftermath. Nevertheless, tendencies towards radial cracking and disking (tensile) failures were indicated for the cement-sheath layer as the system reaches radial stress and displacement continuity, after cement setting.

E&amp;P Notes (September 2022)

E&amp;P Notes (September 2022)

Numerical models of normal faulting at the St. Malo anticline, deepwater Gulf of Mexico, USA

Two-dimensional, plane-strain finite element numerical models produce small normal faults similar to those formed during the Oligocene to Miocene of the salt-cored St. Malo anticline in the deepwater Gulf of Mexico. The mechanical stratigraphy used in the models was derived from well data and a rate-independent, elastic-plastic constitutive model with a non-associated flow rule was used to represent the behavior of weak, over-consolidated rocks. Motion of salt is modeled by displacing the base of the overburden from an initially flat configuration to the observed present-day geometry. Model results using dominantly vertical displacement with minor extension (2%) are consistent with observed faulting at St. Malo. Small amounts of contraction (2–5%) in the numerical model suppress normal faulting whereas 2% extension best reproduces the observed structural style. The normal faults develop during elastic-plastic bending and evolve from sub-vertical, plastic mode-I failure zones to dominantly inclined normal faults. Throws of normal faults produced by the numerical models range from 11 m to 123 m. By comparison, the throws observed in the crest of the St. Malo anticline range from 30 m to 300 m. Models only using vertical displacement develop normal faults with ≤50 m throws due to bending; these are below seismic resolution. Only models with ≥2% extension develop normal faults that would be detectible (i.e., throws ≥50 m). A constraint of all the models is that the top of the salt is not faulted. The maximum depth of normal faulting in the models is ca. 900 m below the top of the reservoir. The maximum throws at the top of the reservoir in the models are ca. 30–65 m. Initiation of the normal faults as plastic mode-I failure zones in the numerical models suggests a mechanism that could facilitate early seal breach, even without juxtaposition of stratal leak points.

Deprimary reverse time migration angle gathers with a stabilized Poynting vector

Deprimary reverse time migration (RTM) mitigates the problem of low-wavenumber noise and false events in conventional RTM, and the generation of high-quality angle-domain common-image gathers or angle gathers during deprimary RTM greatly extends its further applications in velocity model updating and subsurface parameter inversion. Poynting-vector-based methods are the most efficient approach to extract angle gathers from RTM or deprimary RTM. However, the instability problem of Poynting-vector-based methods seriously degrades the quality of the generated angle gathers. The instability problem arises from the oscillatory nature of the Poynting vector. To overcome this issue, we propose a novel approach by harnessing the extra simulated Hilbert transformed wavefield in deprimary RTM. Our approach consists of adding the conventional Poynting vector with an ancillary one derived from the Hilbert transformed wavefield, which allows us to eliminate the oscillatory nature of the conventional Poynting vector and obtain a stable algorithm to extract high-quality angle gathers from RTM or deprimary RTM. By using numerical examples with two synthetic data sets and a field data set from the deepwater Gulf of Mexico, we prove the effectiveness of our method in generating high-quality angle gathers.

New Life for Old Iron in the US Gulf

Reduce. Reuse. Recycle. We’ve all heard the mantra and likely recall it as our grade school introduction to the world of recycling. On a personal level, that meant collecting tin cans, flattening cardboard, or gathering plastic or glass receptacles. Many of these waste products return to industry and reemerge as something new and are kept out of a landfill, at least temporarily. When it comes to recycling in the oil and gas industry, many have looked at assets that have reached their end of life in one service and attempted to repurpose them for another. Offshore rigs have been sold out of the industry to become everything from early warning radar stations for the US military (see the SBX-1) to potential offshore launch pads for Elon Musk’s SpaceX program and beyond. Many offshore platforms in the Gulf of Mexico (GOM) either find their way to the scrap yard or into the rigs-to-reefs program, which reuses old, fixed platform jackets as fresh ecosystems for marine life. However, something that is often talked about but rarely occurs is the reuse of an existing, but idled, production platform on a new field. This appears to be the fate of Independence Hub (IHub)—the floating centerpiece to an ambitious Anadarko Petroleum-led $2-billion deepwater GOM project that aligned several different players and various natural gas discoveries in the mid-2000s (OTC 31155). The last well at IHub ceased production in December 2015, after just 8-plus years of operation. The facility hosted produced volumes of more than 1.3 Tcf of gas, exceeding initial projections for the project by more than 30%. IHub was idled soon after and ultimately decommissioned in 2019. A New Lease on Life In May, offshore producer LLOG acquired IHub; it plans to modify the deep-draft, semisubmersible platform to develop a pair of discoveries in the Keathley Canyon area of the GOM. The reborn platform will be renamed Salamanca and will host oil and gas production from the Leon find in Keathley Canyon Blocks 642, 643, 686, and 687 and the Castile discovery (formerly Moccasin) in Block 736. As currently envisaged, two wells from Leon and one well from Castile will be tied back to the unit at its future installation site in Block 689 in 6,400 ft of water. Initial production from the joint development is expected in mid-2025. “By modifying a previously built production unit compared with constructing a new facility, we are able to reduce significantly the time and cost to bring these discoveries online,” said Philip LeJeune (according to his LinkedIn), president and chief executive of LLOG. “This development will add a significant new source of needed domestic oil and natural gas production when it comes online.”

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)

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

E&amp;P Notes (May 2022)

E&amp;P Notes (May 2022)

Hypothesis for the origin of anomalous VP/VS ratios in GOM subsalt mudrocks: Implications for pore pressure prediction

Acoustic properties of subsalt mudrocks from the Gulf of Mexico (GOM) often display unusual VP/VS ratio behavior that has been attributed to differences in the vertical and horizontal stress states below base salt. The observed VP/VS ratios are higher relative to established GOM mudrock calibrations, returning to trend with increasing depth below base salt. In the Mississippi Canyon area of the GOM, temperatures at base salt are lower by up to 40°F relative to the regional thermal gradient. The present study tested the hypothesis that the unusual mudrock acoustic properties were caused by precipitation of halite in mudrock pores due to cooling of a halite-saturated brine, caused by conductive loss of heat through overlying salt. A drop of approximately 40°F from 235°F for the normal thermal gradient, to the present-day subsalt temperature of 190°F, results in a reduction of soluble halite at saturation of up to about 30 volume percent (vol%). A Gassmann fluid substitution model in which solid halite replaces brine in mudrock pores was used to test this hypothesis. The results of the Gassmann fluid substitution model reproduce the observed acoustic log responses measured in subsalt mudrocks from prospect B, a deepwater GOM subsalt discovery. The results show that about 30 vol% solid halite could explain most of the observed deviations in VP/VS ratio, with model and observations returning to normal VP/VS behavior with 5%–10% solid halite substituted for brine at approximately 2500 ft below base salt. P-wave velocity-void ratio–vertical effective stress (VP-∊-σv) pore pressure models have traditionally fared poorly in subsalt mudrocks. Such models generally rely on VP-porosity relationships that are controlled by compaction in which the vertical effective stress, i.e., overburden stress, is the maximum historical stress. These conditions of stress and porosity are clearly not satisfied in subsalt mudrocks. Predicted velocities are too fast, inferred porosity and void ratios are too low, and subsequent estimates of pore pressure are too high. The model discussed in this paper explains the apparent disconnect between predicted and observed subsalt mudrock porosities and offers a relatively simple method for correcting them using the results of the Gassmann halite-brine fluid substitution model.

Unsupervised Machine Learning, Multi-Attribute Analysis for Identifying Low Saturation Gas Reservoirs within the Deepwater Gulf of Mexico, and Offshore Australia

An effective method of identifying and discriminating undersaturated gas accumulations remains unresolved, resulting in uncertainty in hydrocarbon exploration. To address this problem, an unsupervised machine learning multi-attribute analysis is performed on 3D post-stack seismic data over several blocks within the deepwater Gulf of Mexico and within the Carnarvon Basin, offshore Australia. Results reveal that low-saturation gas (LSG) reservoirs can be discriminated from high-saturation gas (HSG) reservoirs by using a combination of instantaneous attributes that are sensitive to small amplitude, frequency, and phase anomalies with self-organizing maps (SOMs). This methodology shows promise for de-risking prospects, even if it is not quantitative, particularly in frontier and exploration basins where wells may not exist or be very limited. However, this method only proved to be successful within the Gulf of Mexico and yielded limited results in the Carnarvon Basin. This difference is most likely due to the Carnarvon Basin having a different amplitude response resulting from a different burial history and fluid saturations when compared to the Gulf of Mexico. Therefore, this method is non-transferrable, and a different combination of attributes may be needed in other LSG-prone basins.