Wilcox Formation Research Articles

Testing and Application of a Probe Permeameter in the Lower Wilcox Formation, Onshore Texas, USA

Testing and Application of a Probe Permeameter in the Lower Wilcox Formation, Onshore Texas, USA

When the levee breaks: Visualization of a deepwater crevasse splay in Late Cretaceous in Exmouth Basin Offshore Western Australia

“The present is the key to the past” is a foundational geologic concept that helps us contextualize buried subsurface features in current geologic analogs. As seismic interpreters, the generation of the geologic model should be unbiased, yet as humans our unconscious biases are expected, and we sometimes overlook anomalous reflection patterns in our seismic data that do not fit the model. As a result, we often disservice ourselves when we overlook these characteristics, potentially ignoring additional geologic context. These anomalous geoforms or funny-looking things (FLTs) may provide further geologic context and aid us in solving the geologic model if included. Crevasse splay on a continental slope marine environment is described and analyzed using attributes, seismic inversion, and voxel-based classification. We discuss possible causes that may have triggered the break of the levee on the Exmouth Basin during the Early Eocene and why a crevasse splay on a steep slope is an FLT. A possible explanation is that the presence of preexisting faults beneath said feature is the likely culprit for a levee break that created the crevasses splay. Thus, in contrast with the Led Zeppelin song about why the levee breaks, it is equally important to understand the preexisting faults when analyzing sediment supply. In addition, this highlights the importance of integral stratigraphic sequence interpretation — from deep to shallow — to understand geology in a full context. Geologic feature: Crevasse splays and distributary channels Seismic appearance: Mounded high-amplitude reflection with hummocky low-amplitude internal reflection on vertical section, subparallel overlapping sinuous features on seismic attribute horizon slice Alternative interpretation: Mass-transport deposit, avulsion node; channel overbank Formation: The Wilcox Formation Age: Early Eocene-Late Paleocene Location: Offshore Western Australia Seismic data: Stybarrow 2008 M4D MSS obtained by the Geoscience Department of Australia Analysis tools: Coherence, multispectral coherency, principal curvature (K1 and K2), acoustic seismic inversion, flatness and curvedness, CNN automatic fault interpretation, and spectral decomposition

Tectonic preconditioning of recurrent large scale canyon incisions; example from Cretaceous and Paleogene of northern Gulf of Mexico

A 100–150 km-wide clustering of six large Late Cretaceous to Paleogene basin margin slope incisions along the northern Gulf of Mexico, up to 1000 m deep and 100 km long suggest a structural rather than eustatic control on their development. Counterintuitively to the existent models for canyon formation, the incisions align with the basinward trend of the San Marcos Uplift instead of forming in front of large adjacent sedimentary depocenters of the Rio Grande and Houston embayments where large rivers were discharging. Three plausible mechanisms are proposed for canyon formation, both triggered by tectonics. A shelf edge bulge scenario proposes, somewhat similar to previous continental flexure theory, a slow vertical rise of the sub-regional uplift onto the shelf and shelf-edge area that increased the gradient, triggered the initial incision and supported long term headward erosion. The high uplift rate scenario suggests a fast-vertical rise and extension of the uplift into the inner shelf area, whereby the high uplift rate diverted the rivers away from the area and protruded the shorelines as a headland. A third model envisions a deltaic headland caused by a tectonically locked (by uplift) river valley. The structural or deltaic headland diverted the longshore currents and sediment transport basinward, eventually causing a cascading over the shelf-edge and initiating incision and formation of the canyons. Erosion by sediment-laden flows played a critical role in initiating canyon formation, but with tectonics playing a preconditioning role. Other uplift regions around the Gulf of Mexico, Sabine, LaSalle and Tamaulipas (in Mexico) arches also align with large Wilcox Formation sedimentary incisions offshore, strongly suggesting that tectonism was a main control on canyon formation.

Ichnoassemblages from the Wilcox Formation in the Burgos Basin, northeastern Mexico

Abstract An ichnological analysis of the Paleocene–Eocene Wilcox Formation at San José de la Laja and La Curva localities within the Burgos Basin in northeastern Mexico revealed seven ichnogenera: Chondrites , Diplocraterion , Ophiomorpha , Palaeophycus , Planolites , Sinusichnus and Skolithos . The trace fossils were grouped into different ichnoassemblages, including a detailed facies analysis. These results show their apparent association with the Skolithos and Cruziana Ichnofacies in the two studied localities. The integrative analysis of trace fossils and lithofacies made it possible to infer plausible depositional environments for registered periods of fair-weather conditions in both localities of the Burgos Basin, which represent ecosystems characterized by low diversity and abundance. In San José de La Laja, the environment varies from storm affected to tidal setting. In La Curva, lithofacies and ichnology are modulated by storm events in a transitional shoreface, coastal bar and intertidal setting within a deltaic plain. Both localities indicate a shelf impacted by deltaic processes and storm events. Living conditions for most endobenthic organisms were harsh. These results support a long-term regression of the coastal zone during the Paleogene–Neogene and suggest a palaeoenvironment similar to this in the south of Texas during the Paleogene.

Understanding controls on the geochemistry of hydrocarbon produced waters from different basins across the US.

The most massive waste stream generated by conventional and unconventional hydrocarbon exploration is the produced water (PW). The costs and environmental issues associated with the management and disposal of PW, which contains high concentrations of inorganic and organic pollutants, is one of the most challenging problems faced by the oil and gas industry. Many of the current strategies for the reuse and recycling of PW are inefficient because of varying water demand and the spatial and temporal variations in the chemical composition of PW. The chemical composition of PW is controlled by a multitude of factors and can vary significantly over time. This study aims to understand different parameters and processes that control the quality of PW generated from hydrocarbon-bearing formations by analyzing relationships between their major ion concentrations, O, H, and Sr isotopic composition. We selected PW data sets from three conventional (Trenton, Edwards, and Wilcox Formations) and four unconventional (Lance, Marcellus, Bakken, and Mesaverde Formations) oil and gas formations with varying lithology and depositional environment. Using comparative geochemical data analysis, we determined that the geochemical signature of PW is controlled by a complex interplay of several factors, including the original source of water (connate marine vs. non-marine), migration of the basinal fluids, the nature and degree of water-mineral-hydrocarbon interactions, water recharge, processes such as evaporation and ultrafiltration, and production techniques (conventional vs. unconventional). The development of efficient PW recycle and reuse strategies requires a holistic understanding of the geological and hydrological history of each formation to account for the temporal and spatial heterogeneities.

Prestack simultaneous inversion for delineation of the Lower Wilcox erosional remnant sandstone beneath the Texas Gulf Coastal Plain: A case study

The Lower Wilcox lowstand sand deposits encased between two sequence boundaries along the Texas Gulf Coastal Plain are of good reservoir quality and usually gas productive. However, the sedimentation is sparsely scattered within such a depositional environment and it is hard to predict by qualitative interpretation methods. Simultaneous inversion of elastic parameters such as P-impedance, S-impedance, and density by the integration of prestack data and well logs allows us to quantitatively characterize the reservoirs and to distinguish them from the surrounding rocks. We have used prestack simultaneous inversion of the elastic parameters for delineation of the gas reservoir in an active field with limited log availabilities. For wells that are missing sonic and density logs, we estimate the parameters using the time-average equation (TAE) and Gardner’s equation, respectively. The shear wave velocity estimation methods are tested and compared using the measured log value. The estimation results are verified using well-log correlations in adjacent wells. Rock-physics analyses on wells are conducted to find the optimal elastic parameters for characterizing the gas-bearing sand. We successfully delineate the reservoir using the crossplot of VP/ VS versus S-impedance values. The inversion results are quality controlled by a producing well in the reservoir zone, and probability maps of each lithology are calculated by the probability density function. Our results from the Lower Wilcox Formation indicate that simultaneous inversion based on the estimated parameters using TAE is feasible, and the gas-bearing reservoirs can be recommended with high confidence.

Comment on: “A Paleogene ichnological record from the Wilcox Formation: Ophiomorpha and Venericardia (Venicor) zapatai in the Burgos Basin, northern Mexico” by M.I. Hernández-Ocaña, E. Chacon-Baca, S.A. Quiroz-Barroso, S. Eguiluz-de Antuñano, F. Torres-de la Cruz, and G. Chávez-Cabello

In their 2019 paper, “A Paleogene ichnological record from the Wilcox Formation: Ophiomorpha and Venericardia (Venicor) zapatai in the Burgos Basin, northern Mexico,” Hernández-Ocaña et al. present a stratigraphic, sedimentological, and paleontological reconstruction of the Wilcox Fm. from a limited section located in the western part of the Burgos Basin. In my opinion, this paper contains a series of grave errors that puts in doubt the authors’ correlation with the Eocene Wilcox Fm., determination of the species Venericardia (Venericor) zapatai, and stratigraphic interpretation of the described sequence.

E&P Notes (June 2019)

Blacktip: Shell’s New Discovery in the Gulf of Mexico The newest deepwater find in the Gulf of Mexico will be known as Blacktip. It is located about 250 miles south of Houston in about 6,200 ft of water. Shell announced the discovery in late April, calling it the “second material discovery” in what the firm terms the “Perdido Corridor,” according to Andy Brown, Shell’s upstream director. A company statement highlighted that the exploratory well intersected more than 400 ft of reservoir pay zone in the prolific Wilcox formation. The deepwater operator is still evaluating and appraising the field as drilling continues to define the reservoir’s extent. Chinese-Owned Operator Claims Longest Permian Lateral Chinese-owned, Houston-based Surge Energy reported that its subsidiary, Moss Creek Resources, drilled the Medusa Unit C 28-09 3AH well in the West Texas Permian Basin to a TMD of 24,592 ft, with a total horizontal displacement of 17,935 ft, or 3.4 miles. Latshaw Drilling & Exploration’s Rig 10 drilled the well, which stayed 100% in zone of the Wolfcamp A formation, over 18 days from surface to total depth utilizing conventional mud motor and measurement-while-drilling technology. It is the longest known lateral in the Permian based on the IHS and Drillinginfo databases, Surge said. Murphy Oil to Buy Deepwater US Gulf Assets for up to $1.625 Billion Murphy Oil has agreed to acquire deepwater US Gulf of Mexico assets from LLOG Exploration for up to $1.625 billion. The deal will result in the El Dora-do, Arkansas-based Murphy adding 32,000–35,000 BOE/D net to its 2019 US gulf production, of which 60% will be oil, bringing its total US gulf output to 85,000 BOE/D net. The gulf will represent 66% of the company’s total daily production. “With this transaction, Murphy becomes the eighth-highest producer in the Gulf of Mexico. Only a year ago, they were No. 20,” said Imran Khan, senior research manager, US Gulf of Mexico upstream oil and gas, at consultancy Wood Mackenzie, in comments on the deal. ExxonMobil’s Guyana Offshore Discovery Count Rises to 13 ExxonMobil’s Yellowtail-1 well on the Stabroek Block offshore Guyana encountered 89 m of “high-quality, oil-bearing sandstone,” the major said, bringing its discovery count in Latin America’s emerging oil powerhouse to 13. Located 10 km northwest of the Tilapia discovery, the Yellowtail-1 was drilled by the Noble Tom Madden drillship to 5,622 m in 1,843 m of water. Yellowtail-1 is the fifth discovery in the Turbot area—which includes the Tilapia, Turbot, Long-tail, and Pluma discoveries—where ExxonMobil plans another Stabroek Block development hub. Yellowtail-1 adds to the 5.5 billion BOE in estimated recoverable resources on the block. Majors, IOCs Win Blocks in Argentine Offshore Bid Round Thirteen companies placed bids on 18 blocks in the Austral, North Argentina, and Malvinas West basins as part of Argentina’s first open bid round for offshore acreage in more than 20 years. Nearly every major came away with blocks while other international oil companies and South American-focused operators also gained acreage, pushing total bids to almost $1 billion. Among them, Equinor took seven blocks, Qatar Petroleum (QP) received five, and ExxonMobil counted three. Other companies receiving tenders were Total, Shell, BP, Eni, Wintershall, Tullow, Mitsui, YPF, Pluspetrol, and Tecpetrol.

A Paleogene ichnological record from the Wilcox Formation: Ophiomorpha and Venericardia (Venicor) zapatai in the Burgos Basin, northern Mexico

The present paper address the occurrence of Venericardia shell concentrations distributed over hundreds of meters along terrigenous horizons as a typical sedimentary facies of the Wilcox Formation in the Burgos Basin. These extensive deposits overlie Paleogene sandstones so common around the municipality of China, Nuevo León, that they are almost overlooked. This report documents for the first time the ichnological assemblage and shell accumulations of the Paleogene in the Burgos Basin. Ophiomorpha cf. nodosa and Ophiomorpha isp. from Skolithos ichnofacies are the main identified trace fossils; the probable paleoenvironment is a near-shore shallow sea under high-energy conditions related to coastal bars. The analyzed taphonomic features suggest that Venericardia shell concentrated or accumulated as bioevents resulting from intermitent tempestites in the proximal zone. These accumulations are composed of the species Venericardia (Venicor) zapatai organized as regular and linear shell arrangements contained within a frail sedimentary matrix from which they are easily-extracted.

Predicting flow properties in diagenetically-altered media with multi-scale process-based modeling: A Wilcox Formation case study

Two approaches to capture the complex texture of Wilcox sandstone samples in a pore-scale model are employed: a process-based method and an image-based method. In the process-based method, petrographic analyses from transmitted light microscopy are used to infer the diagenetic history of the rock. Key steps in the diagenesis are quantitatively followed using a multi-scale pore-network modeling method to reconstruct the porous medium at different times in its history, including the final state. Further information about pore sizes is gathered from scanning electron microscopy and nitrogen adsorption hysteresis measurements. The ability to incorporate texture information of each diagenetic stage of a tight gas sandstone into a predictive multi-scale pore-network model is a novel aspect of this work. In the image-based method, a micro-CT image of the sample is acquired and a pore-network model is extracted based on skeletonizing the resolvable pore space and mapping clusters of micropores to the unresolved porous areas. The paragenesis of the formation was not captured using the image-based method since sufficient details of its history could not be extracted. The process-based and image-based methods produce comparable drainage capillary pressure curves. While the drainage relative permeability curves in both methods display permeability jail effect, they considerably differ from each other quantitatively. The process-based method produced a higher porosity and permeability compared to the image-based method which is potentially due to the lower degree of its disorder. High uncertainties in the petrophysical properties of tight gas sandstones is a costly challenge in their reservoir development. Our work provides insights into the effect of pore texture from different scales on rock fluid properties. Furthermore, the methods demonstrated in this work can be pursued to extrapolate tight gas sandstone petrophysical properties between wells and throughout paragenetic sequences. • An algorithm for the inclusion of oversize pores in process-based modeling is introduced and implemented. • A comparison of process-based and image-based multi-scale pore-network modeling methods in predicting several petrophysical properties is conducted. • Sedimentary rock fragments and dissolving feldspars can be crucial for fluid flow for the Wilcox Formation. • Permeability jail effect is observed during primary drainage using both methods.

3D seismic characterization of the polygonal fault systems and its impact on fluid flow migration: An example from the Northern Carnarvon Basin, Australia

We used high-resolution 3D seismic data and applied seismic attribute analysis to geometrically interpret and characterize the polygonal fault systems in the Paleocene-Eocene sequence of the Rankin Platform Sub-basin, Northern Carnarvon Basin, Australia. The polygonal faults were identified in a stratigraphic sequence dominated by calcareous clay with minor calcilutite at its lower section that changes to argillaceous calcilutite and calcareous claystone at its upper section. Seismic sections and time slices, through multi-attribute (coherence, energy ratio similarity, and curvature) volumes display a dense distribution of normal faults with polygonal shape and small throws in the plain view. The polygonal fault systems (PFS) exist in two well-defined tiers, which can act as pathways for the fluid flow migration. The first tier coincides with the upper section (Early-Middle Eocene Wilcox Formation) with a few faults and the second one coincides with the lower section of the sequence (Paleocene Lambert and Dockrell formations) with a greater number of faults. Proper understanding and interpretation of the polygonal fault systems as non-tectonic extensional faults are a critical issue in assessing the migration pathway for hydrocarbon (gas) through the Paleocene-Eocene sequence in the Northern Carnarvon Basin, and elsewhere in the world.

Controls on Methane Occurrences in Shallow Aquifers Overlying the Haynesville Shale Gas Field, East Texas.

Understanding the source of dissolved methane in drinking-water aquifers is critical for assessing potential contributions from hydraulic fracturing in shale plays. Shallow groundwater in the Texas portion of the Haynesville Shale area (13,000 km2 ) was sampled (70 samples) for methane and other dissolved light alkanes. Most samples were derived from the fresh water bearing Wilcox formations and show little methane except in a localized cluster of 12 water wells (17% of total) in a approximately 30 × 30 km2 area in Southern Panola County with dissolved methane concentrations less than 10 mg/L. This zone of elevated methane is spatially associated with the termination of an active fault system affecting the entire sedimentary section, including the Haynesville Shale at a depth more than 3.5 km, and with shallow lignite seams of Lower Wilcox age at a depth of 100 to 230 m. Thelignite spatial extension overlaps with the cluster. Gas wetness and methane isotope compositions suggest a mixed microbial and thermogenic origin with contribution from lignite beds and from deep thermogenic reservoirs that produce condensate in most of the cluster area. The pathway for methane from the lignite and deeper reservoirs is then provided by the fault system.

In-Well Dual Canned ESP Completion Test To Validate Safe Deployment in Deep Water

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26002, “Testing In-Well Dual Canned ESP Completion System To Validate Safe Deployment in Deep Water: A Collaborative Effort To Understand Surface and Downhole Requirements,” by Kim Tijerina, Baker Hughes, and Carlos Pardo and Andy Hope, Chevron, prepared for the 2015 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed. Deepwater and ultradeepwater completions use numerous hydraulic control lines for control and actuation of downhole equipment. Incorporating a completion system with an in-well lift such as electrical submersible pumps (ESPs) increases the number of electrical lines needed. This paper discusses the planning and execution of a stack-up test (SUT) to determine whether a completion system incorporating a dual canned ESP system with multiple control lines can be deployed efficiently and safely in a deepwater, high-pressure/high-temperature (HP/HT) environment. Introduction Lower Tertiary Play Characteristics and Challenges. Fields in the Lower Tertiary play, also known as the Paleogene, have low porosity (15–25%) and low permeability (<10 md), which reduce the amount of oil that can be recovered without assistance. In addition, Lower Tertiary water depths range from 5,000 ft to more than 10,000 ft; reservoirs are deeper than 26,000 ft; pressures range from 25,000 to 30,000 psi; and temperatures can be higher than 300°F, further complicating production. The Wilcox formation lies in the Lower Tertiary and is divided into the Upper, Middle, and Lower Wilcox on the basis of each section’s stratigraphy. The Lower Tertiary formations can produce large volumes of oil and gas, assisted by high pressure within the formation. However, as the reservoir pressure depletes, adequate production rates cannot be maintained without effective reservoir-pressure maintenance or artificial lift. In shallow-water wells, gas lift assistance has been used and proved effective for production but requires a large gas supply and infrastructure to support production. Another proven technique used for fluid-lift assistance is an ESP system, normally implemented when a well is worked over and recompleted. Placing an in-well ESP artificial-lift system within the primary completion enhances production during the well-pressure- depletion period, preventing the need of at least one workover to install the ESP and preventing deferred production while waiting for a capable rig to perform the workover. In 2009, considerations for in-well lift completions moved forward with conceptual development of a dual canned ESP system in collaboration with an operator. Although dual ESPs have been run before, the use of a dual canned ESP system in the Lower Wilcox requires a significant number of additional completion components that require additional control lines for their operation.

Compelling evidence from eastern Mexico for a Late Paleocene/Early Eocene isolation, drawdown, and refill of the Gulf of Mexico

Outcrops of the Paleocene/Eocene Chicontepec Formation in eastern Mexico have provided a unique opportunity to study exposed time-equivalent sections of the deepwater Gulf of Mexico (GOM) Wilcox Formation. A 2012 study established a stratigraphic framework in the Tampico-Misantla Basin (TMB) and identified sequence boundaries that could not be correlated globally. Fieldwork in 2008 had also established a network of paleocanyons in the basin associated with a particular “54 Ma” sequence boundary. At that time, a Paleocene turbidite basin fed from the northwest was incised by a collection of northeast-facing erosional canyons that coalesced laterally into the main southeast-trending Chicontepec paleocanyon; this canyon network was filled in the Early Eocene. Using the 2012 study chronostratigraphic scheme, recent micropaleontological studies were performed on a unique outcrop containing a bitumen bed within one of these paleocanyons. The results suggest that the basin’s water level fell rapidly by at least 200 m, starting after 55.8 Ma and leading to subaerial exposure of the bathyal beds for a maximum of 850,000 years prior to canyon refill. Evidence of rooting (limonite tubes) occurs in the bathyal turbidites below the bitumen bed. At this time, the paleocanyons in the TMB were eroded by fluvial systems feeding directly into the central Gulf basin, probably a land-locked sea. The interpreted large and rapid fall and rise of the water level between 55.8 and 54.95 Ma supports the “GOM drawdown hypothesis,” i.e., that the GOM may have been isolated from the world’s oceans due to the closure of the Florida straits as the Cuban arc collided with the Bahamas and northeast Yucatán. The timing of the interpreted drawdown coincides with the Paleocene-Eocene thermal maximum (PETM), hinting that the PETM may have been caused or assisted by the release of methane from hydrates in the GOM margins and abyssal plain.

Results of Reservoir Modeling of the Operation and Production of a Recompleted Gas Well in a Geopressured/Geothermal Reservoir in the Wilcox Formation, Texas, for Electricity Generation

Abstract Reservoir modeling of production of hot geothermal fluid and natural gas from a geopressured reservoir in the Wilcox formation, Texas, for geothermal-electricity generation is carried out primarily on the basis of well-log data. The reservoir modeling takes into account operational considerations such as a constant target flow rate, a 30-year reservoir lifetime, and minimum wellhead pressure as well as uncertainty in reservoir parameters such as gas saturation and reservoir volume. The results of the reservoir modeling are presented and their relevance to other similar geopressured/geothermal wells with the potential for natural-gas production is discussed.

Submarine transitional flow deposits in the Paleogene Gulf of Mexico

Gravity-driven flows on the seafloor are the largest, yet least well understood, sediment transport agents on Earth. Recent exploration wells in ultradeep basins have revealed the presence of large sandy submarine fan systems of enigmatic facies types, many hundreds of kilometers from paleocoastlines. These sedimentary deposits often defy conventional turbidite or debrite interpretations, having a character suggestive of deposition from flows with transient turbulent-laminar rheologies. In the Wilcox Formation (Gulf of Mexico), inferred transitional flow deposits have distinctive stratigraphic stacking patterns, from fine-grained debrites to coarser grained turbidites. The vertical sequence of beds is here inferred to reflect the longitudinal bed distribution in response to lobe progradation, and demonstrates a transition from well-mixed turbulent flow, to progressively more rheologically stratified flow, and eventually to fully laminar flow. The progressive development of internal rheological boundaries resulted in a high-concentration but fluidal basal layer, and an upper quasi-laminar layer with an overriding sheared dilute turbidity current. The long runout of the flows is linked to their high silt and clay content; it is most likely flow expansion at the channel-lobe transition that drives flow transformation. This process-based model may be applicable to many deep-water settings and provides a framework within which to interpret the stratigraphic and spatial distribution of these complex deposits.

Designing Multistage Frac Packs in the Lower Tertiary Formation–Cascade and Chinook Project

Summary The Cascade and Chinook Project is located in the Walker Ridge area in the Gulf of Mexico (GOM), 250 miles south of New Orleans in depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth subsea (TVDss), with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in Moraes et al. (2010). Multiple limitations were considered during the initial design phase of the frac-pack program. The fracs were designed taking into account the use of a single-trip multizone (STMZ) sand-control system. Some of these design challenges are briefly discussed by Cunha et al. (2009). Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operational standpoint because of a continuous, multistage frac operation. Some of the operational limitations included service-tool erosion limitations because of maximum pump rates and proppant volumes, overall frac-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool-spacing limitations, and still maximize contact with net pay. This paper addresses the approach taken to develop a fracture-stimulation program for the Lower Tertiary formation in the Cascade and Chinook Project. Some of the major questions addressed during this process include the following: How many fracture treatments are needed? What is the optimum fracture geometry? What is the desired conductivity? How to effectively position the perforation intervals? What is the desired pump rate, and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers, and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations. Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (caused by depth and in-situ stresses) where fracturing is required for both stimulation and potential formation-collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.

Designing Multistage Frac Packs in a Lower Tertiary Formation - Cascade and Chinook Fields

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140498, ’Challenges of Designing Multistage Frac Packs in the Lower Tertiary Formation - Cascade and Chinook Fields,’ by Ziad Haddad, SPE, FOI Technologies; Mike Smith, SPE, NSI Technologies; and Flavio Dias De Moraes, SPE, Petrobras, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed. Offshore frac-pack operational limitations include service-tool erosion, overall fracture-treatment-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. Geological complexities were another major challenge in completing this very thick interval. Perforation intervals had to be placed in a manner to avoid a fault (and thus a potential early screenout), to avoid a water contact, and to comply with tool-spacing limitations, while maximizing contact with net pay. A specific approach was developed to design the fracture-stimulations for a Lower Tertiary formation in the Cascade and Chinook fields. Introduction The Cascade and Chinook fields are 250 miles south of New Orleans in the Gulf of Mexico (GOM) in ultradeep-water depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth (TVD) with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with no effective vertical permeability. It was recognized early on that dealing with the Lower Tertiary formation required a change in focus from a soft-rock frac-pack completion to a hard-rock hydraulic-fracturing completion, similar to those used in the Wilcox formation in south Texas. The secondary objective was to design a sand-control completion to retain the proppant pack and eliminate proppant flowback in screenless hard-rock fracturing completions. To outline a basis of design for future Cascade and Chinook hydraulic-fracturing treatments, the initial planning phase was to develop a complete and comprehensive set of fracture-treatment-design data to be used in developing the preliminary treatment designs and evaluating the material-selection options, and to identify key questions for future wellsite data collection and execution. The full-length paper details this outline. Design Challenges The first well completed in the Cascade field was completed with three propped-fracture treatments in the upper and lower Wilcox zones. The challenge was to complete this very thick interval while avoiding fracturing the oil/water contact and avoiding placing perforations too near the fault at 25,832 ft measured depth (MD).

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.

Characterization of Hydraulically Induced Fracture Network in a Tight Gas Formation Using Treatment and Microseismic Data

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125237, "Characterization of Hydraulically Induced Fracture Network Using Treatment and Microseismic Data in a Tight Gas Formation: A Geomechanical Approach," by Wenyue Xu, Joël Le Calvez, and Marc Thiercelin, Schlumberger, prepared for the 2009 SPE Tight Gas Completions Conference, San Antonio, Texas, 15-17 June. The paper has not been peer reviewed. Large amounts of gas are produced from unconventional tight-gas-sand reservoirs (e.g., Cotton Valley, Lobo, Taylor Sand, and Wilcox formations) and gas-bearing shale formations (e.g., Barnett, Fayetteville, Marcellus, and Woodford). These plays are driven partly by technology and partly by economics. Modern well-log-evaluation techniques and completion methods are required to yield economical wells. In some cases, microseismic-monitoring campaigns are performed in these low-permeability environments to improve the understanding of the induced-fracture network and to go beyond the simple assumption of a symmetric biwing-fracture system. Introduction Use of traditional models, assuming single- or biwing-type induced fractures, has produced successful hydraulic fracturing in conventional reservoirs. However, these models cannot represent the complex nature of induced fractures in unconventional reservoirs with pre-existing fractures. The otherwise straightforward propagation of a simple wing-like hydraulic fracture tends to interact with nearby pre-existing natural fractures. There are indications of microseismic activity being related to stress effects and to actual fluid movement. In some cases, a volumetric hydraulic-fracturing process is indicated. Recent efforts have been made to map the pattern of induced-fracture networks on the basis of observed microseismic-event distribution. These interpretations were not constrained closely by accounting for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures. Fracture-Network Model To characterize the induced-fracture network better, a semianalytical pseudo-3D geomechanical model was developed on the basis of the conservation of injected-fluid mass and mechanical interactions between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically equivalent description of the process of hydraulic-fracture propagation and the characteristics of the induced fractures.