Green Canyon Area Research Articles

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

E&P Notes (September 2022)

E&P Notes (September 2022)

Quantifying the relative contributions of Miocene rivers to the deep Gulf of Mexico using detrital zircon geochronology: Implications for the evolution of Gulf Basin circulation and regional drainage

AbstractSediment routing from hinterland to the deep sea is complicated because it involves evolution of river drainage from source areas to coastal plains and sediment mixing on the shelf and slope by marine currents. Previous regional paleogeographic mapping in the Gulf of Mexico (GOM) has observed a >150 km offset between the middle Miocene paleo‐Tennessee fluvial axis and the associated deep‐sea fan depositional axis, indicating a complicated sediment pathway. We integrate new and published detrital zircon (DZ) U‐Pb age data from fluvial, shelf and deep‐sea deposits to examine the complex Miocene sediment routing system in the northern GOM. These data suggest an increase in sediment load derived from western North America (increased Western Cordillera terranes; <300 Ma zircon age component) from the early to middle Miocene in the deep‐water Green Canyon protraction area. The early Miocene Green Canyon area received sediments mainly from fluvial axes located directly updip: the paleo‐Mississippi River (44%–56%; characterized by Yavapai‐Mazatzal, Mid‐Continent and Western Cordillera sourced 1800–1600 Ma, 1500–1300 Ma and <300 Ma, respectively, and Grenville‐Appalachian sourced 1300–950 Ma and 500–300 Ma age components) and smaller rivers and tributaries draining the Appalachian Mountains (e.g. paleo‐Tennessee River, 18%–43%; mainly Grenville‐Appalachian sourced 1300–9500 Ma and 500–300 Ma age components). In contrast, the middle Miocene Green Canyon deep‐sea fan shows a strong DZ signal from the paleo‐Red River (38%; increased <300 Ma zircon age component), which requires input of additional sediment sources from west of the paleo‐Mississippi system. In addition, the paleo‐Tennessee River, which was a major middle‐Miocene sediment source for the central‐eastern GOM due to uplift and increased erosion of the Appalachian Mountains, is underrepresented (34%; decreased 1300–950 Ma zircon age component) in the middle Miocene Green Canyon fan. We suggest that two mechanisms combined to produce the increased middle Miocene input from western sediment sources and restriction of locally up‐dip Tennessee River sources: (1) regional drainage changes involving middle Miocene capture of the paleo‐Red River and its tributaries by the paleo‐Mississippi River, which at the same time lost some of its eastern tributaries owing to expansion of the paleo‐Tennessee and (2) eastward (clockwise) marine transport of western‐sourced sediment along the shelf or slope, which deflected the paleo‐Tennessee signal >150 km eastward to feed the deep‐sea fan further east, perhaps reflecting intensification of a precursor to the GOM Loop Current.

Debottlenecking Approach Revitalizes Aging Platform by Increasing Production 30%

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203321, “Integrated Debottlenecking Approach Revitalizes Aging Platform by Increasing Production 30% in Gulf of Mexico,” by Ankur Gandhi, Sara L. McConkey, and Jeremy Kimbrough, SPE, Occidental, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Successful identification, evaluation, and management of bottlenecks in a complex offshore production processing system is challenging but can increase daily production significantly. The Constitution platform in the Green Canyon area of the Gulf of Mexico, which was commissioned in 2006 with a nameplate capacity of 70,000 BOPD, is a complex system with four fields in varying stages of development. The complete paper focuses on a multidisciplinary process developed to identify, evaluate, and eliminate interdependent bottlenecks on the platform and its flowline network during a 16-month period; this synopsis details some of these findings. Integrated Process A study and field trial during 2016–17 demonstrated the ability to separate fluids above the design capacity, but the team faced challenges in terms of flow reliability even at lower production rates. Therefore, in 2017, an effort was launched to understand and mitigate this issue. The underlying process used for the effort stemmed from principles of Six Sigma and Gemba walks. The steps of the process, detailed in the complete paper, are as follows: 1. Define 2. Measure and analyze 3. Design 4. Verify and execute 5. Review The process allows the team to see the variance between perception and reality. The results-driven, continuous-improvement approach also increases visibility among leaders, giving them a chance to interact with subject-matter experts (SMEs) and to understand key bottlenecks. Platform Bottlenecks and Responses Reservoir and Subsea Network Deliverability. The rate uplift from the debottlenecking efforts was estimated using a reservoir simulation model that included a fully integrated subsea flow net-work model, which solved the reservoir and flow network equations in the same Newtonian iteration. This type of simulation model particularly is suited for the problem at hand, provided that the reservoir model adequately matches historical well performance and the network model matches historical friction pressure losses as a function of rate. The simulation model predicted that the reservoir should be able to deliver a rate uplift of 30% above the production rate before debottlenecking. Topsides Fluids Processing Debottlenecking: General. The late-life debottlenecking of the platform posed many process engineering challenges, some of which stemmed from the inherent flexibility for which the platform was designed. The multitude of gas paths available led to many viable operating alignments of sources to separators and then separators to compressor stages. One initial exercise for debottlenecking was to develop a matrix of potential future operating modes, which would account for the required operator flexibility, as well as to address compressor downtime and the resulting temporary rerouting of sources. Once this matrix was developed, topsides process simulations were developed for each to identify capacity requirements for each equipment item. As detailed in the complete paper, topsides fluids processes involving the oil-cooling system and oil-system hydraulics were also debottlenecked.

Evolution of gas hydrate–bearing deep-water channel-levee system in abyssal Gulf of Mexico: Levee growth and deformation

Gas hydrate in the Green Canyon area (Block 955) in the northern Gulf of Mexico is hosted by relatively clay-free silty levee deposits bounding a Pleistocene submarine channel. During the initial phase of channel development, the channel axis experienced sediment bypass while silty to sandy flanking levees formed. Development of high levees prompted gravitational collapse along normal faults dipping toward the channel axis. Extension at the levees was accompanied by compression at the channel axis. The gravitational failure caused rotation and displacement of the levee deposits. Later, deposition occurred within channel axis, whereas only fine-grained sediments accumulated on the levees. The change in depositional style is interpreted as the result of reduced height and strength of the turbidity currents moving along the channel at the later stage, which restricted most nonclay fraction sediments to the levee-confined channel. There is no gravitational failure in this stage, probably because relief between the levee crest and channel floor was reduced because of deposition within the channel. The hydrates are almost entirely restricted to the clay-poor levee deposits formed during the early stage of channel development, with minor hydrate accumulation in late-stage channel axial deposits. The silty levee reservoir is compartmentalized because of the presence of gravitational failure surfaces and an extensive network of salt-related normal faults. The results of this predominantly seismic stratigraphic study completed as a part of The University of Texas at Austin/US Department of Energy Deep-Water Methane Hydrate Characterization and Scientific Assessment project should be compared with sedimentological information from analysis of pressurized cores obtained during The University of Texas-Gulf of Mexico 2-1 (UT-GOM2-1) Hydrate Pressure Coring Expedition presented elsewhere in this volume.

Technology Focus: High Pressure/High Temperature (March 2020)

Technology Focus One would think that, in these challenging times, high-pressure/high-temperature (HP/HT) technology and projects would be put on the back burner, with everybody chasing zipper-fractured barrels from shale. Well, it is not so. The rewards in new reserves and profits of being able to develop HP/HT resources efficiently are just too attractive to ignore. So, we can enjoy some major developments on the project and technical side in the past year, and the highlights are offshore. Let us look at the Gulf of Mexico, which has moved from being just a pioneering area for deepwater developments to an area where deep water and HP/HT combine to provide the ultimate challenge for the best engineers. In 2019, we saw first oil from Appomattox, the first producing high-temperature development in the deepwater Gulf of Mexico; and we can congratulate Shell (operator), Nexen, and the China National Offshore Oil Corporation for a job well done. This project also served as the developing ground for the recently issued Bureau of Safety and Environmental Enforcement HP/HT guidance documents, which certainly will make the next projects more streamlined. And lest we forget, it is also a “green” project, with the first combined-cycle power generation facility deployed offshore in the Gulf of Mexico. The next challenge is now the “HP” part of HP/HT, and Chevron took up the gauntlet and is putting the final touches on a new generation of drillship together with Transocean as the drilling contractor, with NOV providing dual 20,000-psi subsea blowout preventers. And, with the sanctioning of the Chevron-operated Anchor 20,000-psi development in the Green Canyon area at the end of 2019, it is anybody’s guess where this drillship will be deployed first. Total is the partner on this development. These two major HP/HT breakthroughs have been made in deep water, in the toughest industry environment seen at least in my lifetime. Who says our industry is not resilient and innovative? In this year’s paper selection, we are focusing on three technical areas where HP/HT and deep water come together: very-high-pressure and -temperature (supercritical) fluid properties, the latest expandable technology used for liner hangers, and the effect of ambient pressure on the pressure rating of well-construction equipment. Who would have thought that, in these challenging days, we would be able to celebrate the marriage of deep water and HP/HT? And this is happening not just in the Gulf of Mexico; we also hear some very interesting developments in Asia/Pacific (the South China Sea) and in the eastern Mediterranean. It is not aerospace or Silicon Valley, but our industry that is still the most innovative and pioneering in the word. We can only hope that the many highly qualified graduates, and especially post-graduates, in petroleum engineering looking for their first jobs are invited on this journey and don’t wander into other industries where their skills would be quickly appreciated. They are the ones we need to use all the new digital tools, such as simulator-based predrilling exercises. From the days of Shearwater to Appomattox and Anchor, we have almost no time left to tap the experience of the deepwater and HP/HT pioneers who are at the tail end of their careers and have so much knowledge to transfer. Recommended additional reading at OnePetro: www.onepetro.org. SPE 195353 Active Cooling Method for Downhole Systems in High-Temperature Environments by Wenkai Gao, China National Petroleum Corporation, et al. SPE 195725 Improving Performance in Elgin HP/HT Infill Drilling Despite Increasing Challenges by Mohammad Alahmad, Total, et al. SPE 197207 Improved Well Design 15,000-psi Cemented Completion To Deliver Faster and Cheaper Complex Deep Gas HP/HT Wells by Hashil Nasser Said Al Naabi, Petroleum Development Oman, et al.

3‐D basin‐scale reconstruction of natural gas hydrate system of the Green Canyon, Gulf of Mexico

AbstractOur study presents a basin‐scale 3‐D modeling solution, quantifying and exploring gas hydrate accumulations in the marine environment around the Green Canyon (GC955) area, Gulf of Mexico. It is the first modeling study that considers the full complexity of gas hydrate formation in a natural geological system. Overall, it comprises a comprehensive basin reconstruction, accounting for depositional and transient thermal history of the basin, source rock maturation, petroleum components generation, expulsion and migration, salt tectonics, and associated multistage fault development. The resulting 3‐D gas hydrate distribution in the Green Canyon area is consistent with independent borehole observations. An important mechanism identified in this study and leading to high gas hydrate saturation (>80 vol %) at the base of the gas hydrate stability zone (GHSZ) is the recycling of gas hydrate and free gas enhanced by high Neogene sedimentation rates in the region. Our model predicts the rapid development of secondary intrasalt minibasins situated on top of the allochthonous salt deposits which leads to significant sediment subsidence and an ensuing dislocation of the lower GHSZ boundary. Consequently, large amounts of gas hydrates located in the deepest parts of the basin dissociate and the released free methane gas migrates upward to recharge the GHSZ. In total, we have predicted the gas hydrate budget for the Green Canyon area that amounts to ∼3256 Mt of gas hydrate, which is equivalent to ∼340 Mt of carbon (∼7 × 1011 m3 of CH4 at STP conditions), and consists mostly of biogenic hydrates.

PENGEMBANGAN FASILITAS KAWASAN WISATA GREEN CANYON DENGAN PENEKANAN ARSITEKTUR BERKELANJUTAN DI KECAMATAN CIJULANG KABUPATEN PANGANDARAN JAWA BARAT

<p><em>Facilities development of Green Canyon Tourism area in Cijulang are motivated by increasing number of visitors every year who tour to Green Canyon, the lack of education facilities, the lack of facilities which acommodate activities dan fulfil visitors convenience, so the purpose of this design is to get a building design that can fulfill the needs and visitors convenience and also accommodate information and education activity by considering environment sustainability of Green Canyon area. The Design’s issue is how to develop facility that suits with the needs and convenience also accommodate infomation and education activity into Green Canyon area’s design. Methods used is sustainable architecture methods. The result is an area design that contain tourism accomodation facility, education and information facility that concern the tourist convenience by applying Architecture Sustainable through waste treatment; mass management in contour which regard to direction of openings to exploit view, orientation, lighting and ventilation into the area; material choice which easily found around the area and renewable; energy efficiency which considering maximizing natural lighting and ventilation in transformation mass building proccess.</em><em></em></p><p><em> </em></p><strong><em>Keywords</em></strong><em>: Area Development, Natural Tourism, Sustainable Architecture, Tourism Area, Tourism Facility.</em>

Depth domain inversion to improve the fidelity of subsalt imaging: a Gulf of Mexico case study

Accurate geophysical reservoir characterisation in complex geologic environments remains a challenge. In particular, conventional methods of amplitude inversion assume that amplitudes in the seismic image are correctly located and can be inverted to elastic parameters from which a true representation of rock proper¬ties can be derived. However, complex geology, often com¬bined with limitations imposed by surface seismic acquisition geometries, can lead to inadequate illumination of subsurface targets, which can have detrimental effects on the amplitudes and phase of the migrated image. Conventional amplitude inversion techniques do not compensate for these amplitude and phase variations. Consequently, imprints of various non-geological effects and a complex overburden will manifest themselves in the results of seismic inversion, leading to less reliable estimation of acoustic and elastic parameters. An additional challenge to accurate amplitude inversion in complex geologic environments is that depth imaging is normally required to obtain a reliable image of the subsurface, while current amplitude inversion techniques are usually implemented in the time domain. This difference in approach between the imaging and inversion steps can compromise the fidelity of the attributes derived from seismic inversion. In order to improve consistency between structural imag¬ing and rock property estimation, a technique has been developed to perform amplitude inversion directly in the depth domain. The inversion workflow uses point spread functions to capture and correct for space-, depth- and dip-dependent illumination effects resulting from the acquisition geometry and complex geology. The amplitude inversion is performed in the depth domain and the output is a reflectivity image and associated acoustic impedance volume corrected for illumina¬tion effects, thus creating more consistent and reliable imaging products and rock property attributes from depth-migrated datasets. This article presents the application of the depth domain inversion workflow to a long-offset full-azimuth (FAZ) dataset from the Green Canyon area of the Gulf of Mexico (GoM) (Letki et al., 2015).

Structural interpretation in color — A new RGB processing application for seismic data

Structure-sharpened continuous red-green-blue (SRGB) color processing allows the interpreter to explore seismic data more thoroughly for geologic features, facilitates the extraction of structures or geobodies along horizons for them, and provides a visualization environment for the interpretation of geologic objects in their spatial context. SRGB-textured horizons and geobodies offer an intuitive interpretation similar to the way satellite images provide visual information about the surface of the earth. A case study that I conducted from the Green Canyon area in the Gulf of Mexico, which is located across the escarpment from the salt canopy to the abyssal plain, illustrated that the SRGB method delivers subtle structures from geologic and flow processes at the seafloor, helps delineate and understand salt sutures and impurities, and provides details about individual stages in deepwater mass transport systems. With all geologic aspects combined, the SRGB method assists in the mapping and assessment of shallow drilling hazards such as gas hydrates and seafloor instabilities.

Predrill prediction of subsalt pore pressure from seismic impedance

A target-oriented, predrill, pore-pressure prediction method using seismically estimated acoustic impedance is applied to recently acquired and processed dual-coil data in the Green Canyon and Walker Ridge areas of the Gulf of Mexico. Three deepwater subsalt wells are used in the study. One was used as a calibration well, and the other two were used as blind wells for comparing prediction results with the measured pore-pressure and mud-weight data. All three wells are in the Green Canyon area, penetrating thick salt bodies. A new seismic-inversion method is used for inversion of seismic impedance. The pore-pressure method uses a direct transform of the inverse of acoustic impedance, with two adjustable parameters. The optimization of the parameters is done through an iterative process to match the pore-pressure gradient obtained from the well acoustic impedance with those of pore-pressure measurements and mud weights within a tolerable range of those data for the calibration well. The optimized parameters are then used to transform the seismic acoustic-impedance volume to pore-pressure gradient volume. The predicted pore pressure at the blind wells from the well impedance and seismic impedance match reasonably with well data.

Incorporation of geology with rock physics enables subsalt poststack inversion: A case study in the Gulf of Mexico

One of the main goals of seismic inversion is to obtain high-resolution relative and absolute impedance for reservoir properties prediction. We aim to study whether the results from seismic inversion of subsalt data are sufficiently robust for reliable reservoir characterization. Approximately [Formula: see text] of poststack, wide-azimuth, anisotropic (vertical transverse isotropic) wave-equation migration seismic data from 50 Outer Continental Shelf blocks in the Green Canyon area of the Gulf of Mexico were inverted in this study. A total of four subsalt wells and four subsalt seismic interpreted horizons were used in the inversion process, and one of the wells was used for a blind test. Our poststack inversion method used an iterative discrete spike inversion method, based on the combination of space-adaptive wavelet processing to invert for relative acoustic impedance. Next, the dips were estimated from seismic data and converted to a horizon-like layer sequence field that was used as one of the inputs into the low-frequency model. The background model was generated by incorporating the well velocities, seismic velocity, seismic interpreted horizons, and the previously derived layer sequence field in the low-frequency model. Then, the relative acoustic impedance volume was scaled by adding the low-frequency model to match the calculated acoustic impedance logs from the wells for absolute acoustic impedance. Finally, the geological information and rock physics data were incorporated into the reservoir properties assessment for sand/shale prediction in two main target reservoirs in the Miocene and Wilcox formations. Overall, the poststack inversion results and the sand/shale prediction showed good ties at the well locations. This was clearly demonstrated in the blind test well. Hence, incorporating rock physics and geology enables poststack inversion in subsalt areas.

Quantitative interpretation for gas hydrate accumulation in the eastern Green Canyon Area, Gulf of Mexico using seismic inversion and rock physics transform

Gas hydrate can be interpreted from seismic data through observation of bottom simulating reflector (BSR). It is a challenge to interpret gas hydrate without BSR. Three-dimensional qualitative and quantitative seismic interpretations were used to characterize gas hydrate distribution and concentration in the eastern Green Canyon area of the Gulf of Mexico, where BSR is absent. The combination of qualitative and quantitative interpretation reduces ambiguities in the estimation and identification of gas hydrate. Sandy deposition and faults are qualitatively interpreted from amplitude data. The 3D acoustic impedance volume was interpreted in terms of high P-impedance hydrate zones and low P-impedance free gas zones. Gas hydrate saturation derived from P-impedance is estimated by a rock physics transform. We interpreted gas hydrate in the sand-prone sediments with a maximum saturation of approximately 50% of the pore space. Sheet-like and some bright spot gas hydrate accumulations are interpreted. The interpretation of sheet-like gas hydrate within sand-prone sediments around faults suggests that fluid moves into the sand zones laterally by conduits. Variations in depths of interpreted gas hydrate zones imply nonequilibrium conditions. Low P-impedance free gas zones within high P-impedance gas hydrate zones imply possible coexistence of hydrate and free gas within the hydrate stability zone. We propose that gas hydrate distribution and concentration are associated with structures, buried sedimentary bodies, sources of gas, and fluid flux.

Recognizing and compensating for interference from the sediment’s background organic matter and biodegradation during interpretation of biomarker data from seafloor hydrocarbon seeps: An example from the Marco Polo area seeps, Gulf of Mexico, USA

A suite of seep samples from the vicinity of the Marco Polo field in the Green Canyon area of the Gulf of Mexico provides an exceptional opportunity to study the impact of interference from sediment background organic matter and alteration by biodegradation on thermogenic hydrocarbons from seafloor seeps. These seep samples contain a range in both the concentration of seeped hydrocarbons present and level of biodegradation experienced. In addition, the subsurface oil that sources the seepage was available for comparison. The results of the study show that it is essential to have the biomarker data from the sediment’s background organic matter when dealing with low concentration seepage. These data provide a means to characterize the contribution of background organic matter to the biomarker distributions. This, in turn, allows the identification of thermogenic hydrocarbons when the concentration of seeped oil in seafloor sediments is low. In high concentration seepage, the hopanes and regular steranes were found to be more susceptible to near-surface microbial alteration, while tricylic/tetracyclic terpanes, diasteranes, monoaromatic steroids, and triaromatic steroids were more resistant. If biodegradation is severe enough, all biomarker compounds are vulnerable to alteration and very little information is preserved. In an effort to reconstruct the altered distributions, low temperature pyrolysis of the seeped oils’ asphaltenes was done to liberate occluded biomarkers compounds. Although biomarkers were recovered, they did not resemble the parent oil. Characteristics of some of the recovered biomarker distributions suggest alteration by biodegradation. This implies the three dimensional structure of the asphaltenes may not offer complete protection from microbial attack. These results demonstrate why interpretation of biomarker data from seafloor seeps can be a difficult task. Care must be taken to recognize contributions from the sediment’s background organic matter as well as identify alteration by biodegradation. Failure to understand these processes can lead to erroneous interpretations being made about the seep’s parent oil and source rock.

Development and Use of High-Density Fracturing Fluid for Deepwater Frac Packs

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116007, "Development and Use of High-Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs," by L. Rivas, SPE, G. Navaira, SPE, and B. Bourgeois, SPE, Chevron, and B. Waltman, SPE, P. Lord, SPE, and T. Goosen, SPE, Halliburton, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 December. The paper has not been peer reviewed. There has been an increase in the number of wells drilled to depths greater than 20,000 ft in the Gulf of Mexico (GOM). Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0- to 1.04-specific-gravity (SG) fracturing fluid would require surface treating pressures greater than 15,000 psi, which exceeds the limit of the flexible treatment line. To solve this problem, a borate-crosslinked high-density fracturing (HDF) fluid with SG of up to 1.38 was developed to reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure. Introduction The Tahiti field is in the GOM in the Green Canyon area where water depths range from 4,000 to 4,300 ft. The discovery well was drilled in 2002. Total depth was more than 28,000 ft. Initial evaluation indicated approximately 400 ft of net pay in the high-quality reservoir sand that was encountered. Subsequent appraisal drilling over the next 2 years resulted in confirmation of the size of the Tahiti field and its status as one of the most significant net-pay accumulations ever discovered in the GOM. The discovery well was re-entered in 2004, and a well test was performed to verify deliverability, dynamic well data, and reservoir properties. A stacked frac pack in the Miocene M21A and M21B sands was planned for the well test. The Tahiti M21A sand averages 60 to 80 ft thick, and the M21B sand averages 120 to 150 ft thick. Permeability ranges from 600 to 800 md. The decision was made to complete both intervals with a single, high-rate frac pack. At the time, at a depth in excess of 25,800 ft, it was the deepest successful well test and frac-pack completion ever carried out in the GOM. The HDF fluid was a key component of the successful Tahiti well test. The well-test results led to the development of the Tahiti field, which began in February 2006. While planning the Tahiti well test, several factors influenced the decision to develop a suitable HDF fluid that would minimize surface treating pressures and allow the fracture job to be pumped at pressures below the 14,000-psi limit. Uncertainty regarding Miocene-pay-sand fracture gradients, and required treating rates, coupled with high friction losses in the treating string led to the desire to find an HDF fluid that would allow the fractures to be pumped at 40 to 45 bbl/min while staying within surface-treating-pressure limitations.

4D time strain and the seismic signature of geomechanical compaction at Genesis

Genesis Field, which lies in the Green Canyon area of the Gulf of Mexico at a water depth of 790 m, consists of a series of unconsolidated Pleistocene/Pliocene-aged turbidite sands, dipping up against a salt-cored ridge. Since first oil in 1999, the field has been under primary production, and, although there is a moderate natural water drive in parts of the field, much of it has undergone significant compaction resulting from pressure depletion. The compaction has had severe economic ramifications, as recently several wells have been lost due to compaction-related shear failure.

Direct seismic indicators of gas hydrates in the Walker Ridge and Green Canyon areas, deepwater Gulf of Mexico

During the past two decades, marine research has focused on gas hydrates because of their potential importance as a future energy source, as a geologic hazard in deepwater hydrocarbon exploration, and because they may impact climate change (McConnell and Kendall, 2003; Smith et al., 2005). Worldwide assessments indicate that gas hydrate reserves may surpass the total hydrocarbon reserves from all other known resources of fossil fuels. Consequently, gas hydrates are considered to be a potential energy source for the 21st century.

Tahiti: Development-Strategy Assessment

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100656, "Tahiti: Development-Strategy Assessment Using Design-of-Experiments and Response-Surface Methods," by P.E. Carreras, SPE, S.E. Turner, SPE, and G. Wilkinson, SPE, Chevron, prepared for the 2006 SPE Western Regional/AAPG Pacific Section/GSA Cordilleran Section Joint Meeting, Anchorage, 8-10 May. The Tahiti field in the deepwater Gulf of Mexico (GOM) is a three-way anticlinal structure trapped against salt. The discovery well was drilled in 2002, and two appraisal wells were drilled soon afterward. Because of significant uncertainties remaining after appraisal, probabilistic methods were used to assess development alternatives. A classical experimental-design method was applied, and reasonable reservoir-simulation models were designed and validated. The proposed workflow enhances use of experimental design by combining the technique with response-surface methods and rational engineering judgement. Introduction Tahiti field is in more than 4,000 ft of water in the Green Canyon area of the GOM, approximately 190 miles southwest of New Orleans. The field was discovered in April 2002 with the drilling of Well GC 640-1. Results from the exploratory well indicated the presence of high-quality reservoir sand with more than 400 ft of total net pay distributed in three main Miocene turbidite sheet sands at depths ranging from 24,000 to 27,000 ft true vertical depth. In 2003, two appraisal wells were drilled simultaneously. One of the appraisals encountered more than 1,000 ft of net pay in high-quality sandstones, confirming one of the most significant net-pay accumulations in the history of the deepwater GOM. The field will be developed in phases. The first development phase was sanctioned in August 2005 by Tahiti joint-venture partners Chevron, Statoil, and Shell at a cost of more than U.S. $1.8 billion. Total capital costs for the project are anticipated to be approximately U.S. $3.5 billion. The field is expected to come on line in mid-2008. Because of significant uncertainties, probabilistic methods were used to assess development alternatives during Phases 2 and 3 of Chevron's project-management process. The main purpose of this study, part of Phase 3 (Develop Preferred Alternatives), was to assess a mature predevelopment strategy. Reservoir Description The Tahiti prospect was identified by use of advanced subsalt 3D-seismic imaging technology, along with geologic-data interpretation to identify the presence of reservoir-sand development, hydrocarbon charge, and migration into a geologic trap. The trap tested by the discovery well is a three-way anticlinal closure truncated against a salt feeder/weld system buried beneath an 11,000-ft-thick subsalt canopy (Fig. 1). On the basis of seismic data and appraisal wells, the trap is estimated to extend approximately 5 miles in a north-to-south direction and 1.5 miles in a west-to-east direction. Main reservoirs are Lower to Middle Miocene. DOE Methodology Design of experiments (DOE) is a methodology that reduces the number of reservoir-simulation runs that must be generated to develop equations for response variables. The response variables usually are economics parameters such as oil recovery or net present value (NPV). DOE provides not only a systematic framework for unbiased decisions but also technical continuity to the study. The understanding of field dynamics increases as the project evolves. The DOE workflow applied in this study comprises nine steps.

A pattern‐based approach for multiple removal applied to a 3D Gulf of Mexico data set

ABSTRACTSurface‐related multiples are attenuated for one sail line and one streamer of a 3D data set (courtesy of Compagnie Générale de Géophysique). The survey was carried out in the Gulf of Mexico in the Green Canyon area where salt intrusions close to the water‐bottom are present. Because of the complexity of the subsurface, a wavefield method incorporating the full 3D volume of the data for multiple removal is necessary. This method comprises modelling of the multiples, where the data are used as a prediction operator, and a subtraction step, where the model of the multiples is adaptively removed from the data with matching filters. The accuracy of the multiple model depends on the source/receiver coverage at the surface. When this coverage is not dense enough, the multiple model contains errors that make successful subtraction more difficult. In these circumstances, one can either (1) improve the modelling step by interpolating the missing traces, (2) improve the subtraction step by designing methods that are less sensitive to modelling errors, or (3) both. For this data set, the second option is investigated by predicting the multiples in a 2D sense (as opposed to 3D) and performing the subtraction with a pattern‐based approach. Because some traces and shots are missing for the 2D prediction, the data are interpolated in the in‐line direction using a hyperbolic Radon transform with and without sparseness constraints. The interpolation with a sparseness constraint yields the best multiple model. For the subtraction, the pattern‐based technique is compared with a more standard, adaptive‐subtraction scheme. The pattern‐based approach is based on the estimation of 3D prediction‐error filters for the primaries and the multiples, followed by a least‐squares estimation of the primaries. Both methods are compared before and after prestack depth migration. These results suggest that, when the multiple model is not accurate, the pattern‐based method is more effective than adaptive subtraction at removing surface‐related multiples while preserving the primaries.

Lessons From Integrated Analysis of GOM Drilling Performance

Summary Offshore drilling continues to be extremely cost intensive, with U.S. $50 million wells not uncommon. This paper discusses one company's experience and the lessons it learned from a comprehensive analysis of Gulf of Mexico (GOM) historical data for drilling-performance benchmarking and continuous cost reduction. Drilling operations were broken down into discrete activities, and the best times from all the wells—including trouble time—were aggregated to form the "best composite time" (BCT). The BCT, introduced in recent papers,1–3 was applied, along with learning-curve analysis and other investigative tools, to examine drilling problems and the lessons learned to capture the best practices and, there by, challenge well-planning and construction practices. The "best composite cost" (BCC), or the monetary equivalent of the BCT, was also calculated and used for well-cost benchmarking. Correlative analyses of the wells (i.e., crossplots of drilling events along side mud-log data, wireline logs, and geologic data) were used to elucidate major well problems and abnormal flat times that caused deviations from the BCT. Correlative analysis also helped explain why some wells were drilled relatively trouble-free, even in difficult environments. From a more detailed trouble-time analysis of company-operated wells, tool/equipment failure was seen as a significant trouble-time component. Major drilling problems were also found to be mostly well-pressure related (e.g.,well control, lost circulation, and stuck pipe), supporting increased emphasison improved planning and quantification of equivalent circulating density(ECD), deepwater geopressures, and narrow drilling margins, especially in ultradeepwater environments. Overall, the company's 2003 trouble time was 26% of the total drilling time from spud to rig release. The BCT/BCC methodology is actually one element of "The Ten-Step Process" discussed exhaustively in Refs. 1 and 2. Applications to two onshore areas, so far, have shown encouraging results in drilling-costreduction. Applications to more-complicated offshore GOM wellbores, cost components, and narrow geopressure margins are the focus of this paper. The fields investigated are located in different parts of the GOM (Table 1). For brevity, results are shown only for the subsalt area of South Timbalier, the deepwater Green Canyon (GC) area, and the ultradeepwater eastern Gulf of Mexico(EGOM).