Salina Basin Research Articles

E&P Notes (December 2022)

E&P Notes (December 2022)

Collaboration Allows Introduction of Automated Advisory System in Offshore Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31443, “Operator and Service Provider Collaborate To Successfully Introduce an Automated Advisory System in a Wildcat Exploration Well Offshore Mexico,” by Peter Batruny, SPE, M. Razali Paimin, and M. Arriffuddin Allauddin, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ The authors of the complete paper describe a collaboration between an operator and a service company formed during a project’s well-planning phase to evaluate the feasibility of automation for a holistic drilling-advisory platform that facilitates real-time decision making based on downhole and surface data. The collaboration resulted in a successful deployment of an automation platform as a solution to manage and mitigate risks and optimize drilling operations in exploration wells. Introduction The probability of nonproductive time (NPT) and invisible lost time (ILT) occurring in exploration wells is higher because of a lack of experience in the area concerned. The operator estimates that NPT caused by hole problems accounts for 22% of total NPT (Fig. 1). The authors’ work aims to apply a novel, automated drilling-operation monitoring technique on a wildcat exploration well in the Gulf of Mexico through the collaboration of operator and service provider. A collaborative framework and technology integration is applied to minimize the effect of uncertainty on NPT and ILT. Description and Application of Equipment and Processes The well is in the Salina Basin, approximately 67 nautical miles north of shore, with an estimated water depth of 66 m below mean sea level. The maximum planned well total depth was approximately 4400 m true vertical depth subsea. The proposed well lies in a four-way anticline structure. Despite the abundance of wells around the location, most exploration activities performed in the area have been focused on the Middle and Lower Pliocene (shallower) interval, causing well correlation at the Miocene stratigraphic interval to be extremely limited. In addition, the disparate thicknesses of the Pliocene sediments in the area create significant challenges in terms of geological correlation. Five offset wells were used as stratigraphy correlation, with distances ranging from 8 to 31 km. Downhole losses and borehole instability were experienced in all offset wells, with well-control events experienced in three out of five offset wells.

E&P Notes (June 2020)

E&P Notes (June 2020)

Reconstructing salt geometry using 3D CSEM data

Abstract In this paper we demonstrate the imaging capabilities of a newly developed 3D Gauss-Newton inversion algorithm for marine controlled source electromagnetic (CSEM) data by inverting synthetic data generated from a known salt resistivity model. We show that the high resistivity contrast between salt and background sediments can be utilized to reconstruct reliable images of the salt structure without the use of any a-priori information which could bias the outcome. Further, we re-invert a CSEM data set acquired in 2012 in the Salina basin in the Gulf of Mexico, using the same 3D Gauss-Newton inversion algorithm. The resulting resistivity model is compared to the initial salt interpretation based on seismic data. The top salt boundary in the inverted resistivity model correlates well with the initial interpretation. However, the base salt geometry, which is often difficult to map with seismic data alone, is imaged very differently. The CSEM inversion result is robust and independent of other geophysical data and therefore very valuable in a salt imaging workflow to support seismic interpretation and velocity model building.

Integrating strike-slip tectonism with three-dimensional basin and petroleum system analysis of the Salinas Basin, California

The Salinas Basin is a strike-slip basin in central California with stratigraphy dominantly composed of Miocene Monterey Formation. Despite a long history of oil production, aspects of petroleum system development in the basin remain poorly understood. Of the seven main oil fields, one—San Ardo field—has produced more than 500 million bbl of oil or 99% of all oil found in the basin. The evolution of this basin was profoundly influenced by strike-slip movement on the Rinconada Fault, which bisected the depocenter beginning circa 15 Ma. To address the influence of strike-slip motion on petroleum system development, we constructed a three-dimensional (3-D) basin and petroleum system model that incorporates strike-slip displacement. Seismic reflection profiles from a 3-D survey reveal four main tectonic stages that correspond to events in petroleum system evolution. Petroleum generation from type II kerogen source rock began circa 11 Ma, approximately 4 m.y. after strike-slip faulting began to offset a once-contiguous sedimentary depocenter. Two separate petroleum provinces—an eastern one and a western one—developed, and the fault zone likely was a conduit for petroleum, if nonsealing. Most accumulated petroleum was derived from the eastern pod of active source rock because of greater sedimentary burial east of the fault. Our model roughly replicates the skewed distribution in oil-field size. Factors controlling field size distribution include trap size and connectivity to source.

Provenance of the Ediacaran Salinas Formation (Araçuaí Orogen, Brazil): Clues from lithochemical data and zircon U-Pb (SHRIMP) ages of volcanic clasts

Abstract Salinas Formation occurs in a large region of the Northern Aracuai orogen, Southeastern Brazil. It includes turbiditic wackes (> 10% matrix) to arenites (< 10% matrix), pelites and clast-supported conglomerates, metamorphosed from the biotite zone of the greenschist facies to the sillimanite zone of the amphibolite facies. Salinas Formation lies unconformably on the top of or in tectonic contact with the Macaubas Group, and hosts Cambrian granitic intrusions dated between 540 and 500 Ma. Aiming to unravel sediment provenances for the Salinas basin, we present a detailed lithochemical (45 samples) study on low-grade rocks preserved from the regional deformation, which are found in the type area of the Salinas Formation. In addition, we compare them with deformed and more metamorphic rocks of similar composition but located in other basin sectors. The lithochemical data indicate limited chemical weathering in the sediment sources, good correlations with the mineralogical compositions in respect to the variable amounts of metamorphic minerals typical of pelitic (micas, garnet, and other peraluminous silicates) and psammitic (feldspars, quartz) fractions. The main provenances of sedimentary protoliths are clearly related to continental magmatic arc and active continental margin environments. U-Pb (SHRIMP) analyses performed on zircon grains from clasts of intermediate to felsic volcanic rocks, extracted from a clast-supported metaconglomerate, yield concordant zircon Pb206 /U238 ages from ca. 579 Ma to ca. 697 Ma, with most of the ages in the interval of 587 to 630 Ma. This indicates that the main primary sediment source is the Rio Doce magmatic arc (630-580 Ma), in very good agreement with the arc-related lithochemical signature. Eleven zircon crystals yield a Concordia age of 620 ± 10 Ma, representing an important Ediacaran volcanic episode in the tectonic evolution of the Aracuai orogen.

Generation of Pseudo-synthetic Seismograms from Gamma-Ray Well Logs of Highly Radioactive Formations

The conventional synthetic seismogram is created with a sonic and a density log; however, the sonic log can be replaced with the resistivity, neutron, gamma-ray or spontaneous potential log to produce a pseudo-sonic (PS) log. More recent techniques involve combining an SP log and a GR log to produce a PS log. In the past, a drawback in using GR logs for the PS is the presence of highly radioactive and often organic-rich layers possessing abnormally high GR readings. To improve the pseudo-sonic log produced from the gamma-ray log, a technique was developed to statistically treat the outliers from the wells in the Hugoton Embayment that encountered predominantly shale, sandstone, limestone, and dolomite and whose logged sections included both normal and abnormally high GR readings. To demonstrate a wider-range application of our method, the procedure was applied to wells from the Hugoton Embayment, Central Kansas Uplift, Sedgwick Basin, Salina Basin, Forest City Basin and Nemaha Uplift. The correlation coefficients between the PS and the conventional sonic for the six basins were 0.75, 0.92, 0.86, 0.91, 0.77, and 0.70, respectively. Also, the match between the resulting conventional synthetic seismogram and the pseudo-synthetic seismogram from a blind test well for each area was quite good. Provided the outliers have been properly treated, the GR log is a viable tool for creating pseudo-sonic logs and pseudo-synthetic seismograms for exploration in oil and gas basins where there are few wells with sonic logs or where sonic log quality is poor.

Mexico’s Second Deepwater Auction Successful

Mexico’s second deepwater bid round failed to disappoint as 19 of 29 blocks were awarded, including nine to Anglo-Dutch supermajor and Mexican offshore newcomer Shell. Eleven international firms from 10 countries bidding individually and in consortia won blocks—thought to be mostly oil-rich—in the Perdido Fold Belt, Cordilleras Mexicanas basin, and Salina basin of the Gulf of Mexico. Nineteen firms from 15 countries placed 39 bids overall. The winning bids comprised 44,178 sq km, 23 well commitments, and $525 million in tiebreak payments. Mexico’s National Hydrocarbons Commission (CNH) announced the results 31 January in Mexico City. Benjamin Torres-Barron, partner at multinational law firm Baker &amp; McKenzie, which represented four of the companies that participated in the round, said the auction was “very successful” with results “better than everybody expected.” Estimates prior to the event, including those of the government, had approximately 7–10 blocks being awarded. Instead, about two-thirds of all available blocks were awarded, making Round 2.4 “a great success for the Mexican government,” said Eduardo Corzo Ramos, counsel with international corporate law firm Haynes &amp; Boone. “Very important companies participated and in the bid values you can see how interested these companies are in Mexico’s energy sector.” Ramos said he was impressed by the strength of the bids and high-dollar tie-breakers placed by the participating firms. “If you look at the winners, everyone was hitting the maximum [royalty of 20%] with a maximum investment factor.” Competition was particularly fierce for Salina basin Blocks 29 and 21, respectively won by Shell and a consortium led by Repsol with tiebreak bonuses of $110 million and $151 million. Shell’s haul comprised four blocks won on its own, four in a consortium with Qatar Petroleum, and one more in a consortium with Pemex. Five were in the Perdido Fold Belt just south of the Mexico-US maritime border, and four were in the Salina basin to the southeast in the Bay of Campeche. “We saw a vast, overwhelming victory by Shell,” said Torres-Barron. “I think Shell was very aggressive based on its prior experience” in Mexico’s first deepwater auction, Round 1.4 held in December 2016, in which the firm’s participation comprised a single failed bid alongside Atlantic Rim Mexico for Block 5 in the Salina basin. Shell learned that “you cannot have all the eggs in one basket,” and therefore diversified its bids through a number of blocks this time around, he said. Shell concurrently announced on 31 January that it made “one of its largest US Gulf of Mexico exploration finds in the past decade” near Perdido in perhaps a signal that a comeback is under way for offshore exploration and development. Chevron and Total, two other majors who have actively participated in Mexico’s deepwater rounds, also reported a US gulf discovery on 31 January.

Lombardi reservoir, San Ardo field, California: Sequence stratigraphy in a deltaic environment associated with local tectoni

The Lombardi reservoir at San Ardo oil field in California is extremely sand rich (>90%) and appears to be a relatively simple reservoir several hundred feet thick. The purpose of this study is to characterize stratigraphic complexities in the Lombardi reservoir that may affect later production and interpret how changes in stratigraphic architecture are tied to local syndepositional tectonism. Two parasequence sets are present in the Lombardi: the reservoir exhibits clinoform geometries along the western edge of the field and stacking patterns within the reservoir change across the field. Based on stacking pattern, core, and correlation studies, two possible sequence boundaries are recognized in the Lombardi sand. A lower sequence boundary is proposed approximately in the middle of the Lombardi sand, and an upper sequence boundary is proposed at the top of the Lombardi sand. In the southern part of the field, the Lombardi sand consists of two progradational parasequence sets, separated by the mid-Lombardi sequence boundary. The upper sequence boundary clearly truncates underlying folded Lombardi sand. Just a few miles (∼5 km) away, in the northwest part of the field, the Lombardi sand consists of a lower progradational parasequence set and an upper retrogradational parasequence set, separated by the mid-Lombardi sequence boundary. The upper sequence boundary at the top of the Lombardi sand shows little evidence of truncation of underlying units and is recognized by onlapping of younger strata. The difference in reservoir architecture between the south and northwest part of the field, a distance of only a few miles (∼5 km), is interpreted to be related to syndepositional uplift accompanying tectonism in the south. In core, the Lombardi sand consists mostly of homogeneous sand and bioturbated sand, arranged in upward-coarsening successions. The Lombardi sand is interpreted to be the product of deltaic deposition based on (1) the presence of homogeneous and laminated sandstones interpreted to represent mass flow deposits and (2) its restricted geographic distribution within the Salinas basin. No evidence of deposition in a wave-dominated or tidal-dominated shoreline is indicated. The interpretation presented here is that the sediments were deposited on the front of a delta emptying into a wave-protected estuary or bay, with minimal tidal effects. Complexities in stratigraphic architecture along the western edge of the field do not currently affect production but will likely become important during later stages of field development. That is, in the developed part of the field, reservoir continuity is not an issue, because of high sand content and sheet-like geometries. However, at the margins of the field, which will be produced in the future, clinoform geometries and sandstone tongues clearly affect reservoir continuity and will create vertical compartments during draining.

Mexico Awards Its First Deepwater Blocks; What Comes Next?

Mexico’s historic public tender for its deepwater real estate resulted in the awarding of eight out of 10 blocks on offer. Held last December in Mexico City, the event marked the fourth and final auction of the country’s Round One, which reopened doors to foreign oil and gas investment for the first time since the country’s energy sector was nationalized almost 80 years ago. The awarded blocks went to 13 companies whose exploration and production operations are expected to generate around USD 34 billion over the next 15 years. The winning bids also committed to drill at least eight deepwater wells. All four blocks offered in the deep-water Perdido area were awarded, including two to Chinese Offshore Oil Corporation (CNOOC) and one to a consortium of Chevron, Pemex, and Inpex—Japan’s largest oil company. An additional four blocks in the Salina Basin were contracted to three different consortiums, including one formed by Statoil, BP, and Total. Another block encompassing a deep-water discovery known as the Trion field was awarded as a farmout agreement between BHP Billiton and Mexico’s state-owned oil company Pemex. BHP will acquire 60% of the project’s interest under the terms of the contract, which it won through a tie-breaking offer of a USD 624 million cash bonus to Mexico’s petroleum fund. BP was the losing bidder. Including the three previous onshore and shallow-water auctions, Mexico has awarded 39 exploration and production contracts to companies from nine foreign countries. In a press conference following the auction, the government said it expects to receive close to 60% of the combined profits from the eight blocks and the lone farmout. Mexican officials also said they are hoping the deepwater contracts eventually will yield 900,000 B/D of crude, a volume that would help stem the country’s declining production from existing fields. Government officials added that first production from Trion might be reached within 6 years, while it is expected that the other areas will need up to a decade to be developed. What’s Next? According to many observers, the production potential that the deep water holds for Mexico was the chief driver behind the country’s sweeping energy reforms that became law in 2013. But now that a number of the prime blocks have been allocated, what comes next? For the companies that have already signed offshore contracts, their next steps are likely to include the expansion of Mexico’s port facilities to accommodate the arrival of larger deepwater vessels and rigs. Some expect the small port town of Dos Bocas to become a deepwater hub because of its proximity to the southern Salina Basin blocks.

Superimposed extension and shortening in the southern Salinas Basin and La Panza Range, California: A guide to Neogene deformation in the Salinian block of the central California Coast Ranges

We synthesized data from geologic maps, wells, seismic-reflection profiles, potential-field interpretations, and low-temperature thermochronology to refine our understanding of late Cenozoic extension and shortening in the Salinian block of the central California Coast Ranges. Data from the La Panza Range and southern Salinas Basin document early to middle Miocene extension, followed by Pliocene and younger shortening after a period of little deformation in the late Miocene. Extension took place on high-angle normal faults that accommodated ∼2% strain at the scale of the ∼50-km-wide Salinian block (oriented perpendicular to the San Andreas fault). Shortening was accommodated by new reverse faults, reactivation of older normal faults, and strike-slip faulting that resulted in a map-view change in the width of the Salinian block. The overall magnitude of shortening was ∼10% strain, roughly 4–5 times greater than the amount of extension. The timing and magnitude of deformation in our study area are comparable to that documented in other Salinian block basins, and we suggest that the entire block deformed in a similar manner over a similar time span. The timing and relative magnitude of extension and shortening may be understood in the context of central Coast Range tectonic boundary conditions linked to rotation of the western Transverse Ranges at the south end of the Salinian block. Older models for Coast Range shortening based on balanced fault-bend fold-style cross sections are a poor approximation of Salinian block deformation, and may lead to mechanically improbable fault geometries that overestimate the amount of shortening.

Kansas Energy Sources: A Geological Review

Kansas produces both conventional energy (oil, gas, and coal) and nonconventional (coalbed gas, wind, hydropower, nuclear, geothermal, solar, and biofuels) and ranks the 22nd in state energy production in the U.S. Nonrenewable conventional petroleum is the most important energy source with nonrenewable, nonconventional coalbed methane gas becoming increasingly important. Many stratigraphic units produce oil and/or gas somewhere in the state with the exception of the Salina Basin in north-central Kansas. Coalbed methane is produced from shallow wells drilled into the thin coal units in southeastern Kansas. At present, only two surface coal mines are active in southeastern Kansas. Although Kansas has been a major exporter of energy in the past (it ranked first in oil production in 1916), now, it is an energy importer.

A New Look at an Old Petroleum Province

New petroleum paradigms in mature basins can be derived from re-examining geological parameters without bias of preceding theory. Kansas has a long history of oil and gas production with over 300,000 wells drilled. Precambrian basement faults in Kansas control the development of later structures, and probably, reservoirs. This study and re-interpretation of geologic history has identified a possible new play along reverse and thrust faults of the Humboldt Fault Zone along the eastern margin of the Nemaha uplift. This paper also suggests that the lack of significant petroleum production in the Salina basin is the result of migration barriers created by faults at the junction of two major fracture trends, rather than by limited local generation and migration.

CULTURAL EVOLUTION AND WATER MANAGEMENT IN THE SALINAS RIVER VALLEY1

ABSTRACT: This article reports the findings of a case study of a major California water management district's effort to change its management approach. The following key findings and factors have influenced the Salinas basin management plan (BMP) and its progress: (1) the Salinas Valley is an economy dominated by highly sophisticated irrigated agriculture dependent on ground water; (2) a persistent pattern of agricultural overdraft of ground water has hurt growers primarily in the north end of the valley via induced saline intrusion of irrigation wells; (3) a complex set of water institutions, property and water rights, and land lease practices offer little incentive for good stewardship of land and water; and (4) the BMP approach initially may have intensified tension among growers and between growers and other water user groups. Water rules and practices in the Salinas Valley and Monterey County have evolved through a long historical process of adaptations. Therefore, any significant changes in local water use practices need to be understood in terms of cultural change, that is, changes in deeply held values, beliefs, and assumptions. We believe the BMP and the MCWRA are succeeding when evaluated from this evolutionary perspective. The fact that both still exist relatively intact testifies that they are working, albeit slowly.

A Petroleum System for the Salina Basin in Kansas Based on Organic Geochemistry and Geologic Analog

The Salina Basin historically has been an “exploration desert”—a home of dryholes. Although this basin, which underlies much of north-central Kansas, may never be a prolific source of hydrocarbons, recent research into the maturation and geochemistry of organic matter and oils in Kansas can provide guidelines for a new exploration strategy. The Salina Basin is similar to the oil-productive Forest City Basin in northeastern Kansas in many ways. Both basins originated as a single large basin (i.e., the North Kansas Basin) prior to the rise of the Nemaha Uplift in Late Mississippian-Early Pennsylvanian time. Their Paleozoic stratigraphy thus is similar and the axes of both basins are presently at approximately the same depth. Thermal maturation modeling and available organic-matter maturation data indicate that the lower Paleozoic rocks in the axes of both basins are in the early stages of oil generation. In the Forest City Basin the Ordovician Simpson Group is the deepest known hydrocarbon source-rock—oil-reservoir interval, and by analogy, exploration tests in the Salina Basin, at a minimum, should penetrate through this stratigraphic interval. Ordovician Simpson Group shales in the Forest City Basin are the source rocks for a geochemically distinct oil, which also occurs in Ordovician reservoirs in the extreme southern end of the Salina Basin. To increase the odds of success in an exploration program in the Salina Basin, wildcat wells should be drilled where thermal maturation is greatest. The broad NW–SE-trending basin axis is the most logical area. Exploration tests along this axis in the northern end of the basin may have an extra advantage as organic matter in the Simpson Group may be more thermally mature because of greater burial depth during the Cretaceous. Along the eastern margin of the nearby Central Kansas Uplift and Pratt Anticline, several Paleozoic geologic structures, some of which contain major oil fields, are attributable to tectonic reactivation along the western margin of the Precambrian Central North American Rift System (CNARS). Prospective structural trends in the Paleozoic section of the Salina Basin are anticipated to be associated with this underlying tectonic boundary. The western margin of the CNARS trends NNE–SSW where it passes under the axis of the Salina Basin in northeastern Lincoln and southeastern Mitchell counties. This area is sparsely drilled, with less than two tests per township. If an exploration program can define lower Paleozoic structural closures in this region, these structures may represent the best chance for future petroleum discoveries.

Abstract: Subtle and Not-So-Subtle Anticlinal Structures in the Salina Basin, North-Central Kansas

Abstract: Subtle and Not-So-Subtle Anticlinal Structures in the Salina Basin, North-Central Kansas

Abstract: New Exploration Concept in the Salina Basin, Southeast Mexico

Abstract: New Exploration Concept in the Salina Basin, Southeast Mexico

Abstract: Paleomagnetism Applied to the Monterey Formation of California: Results from the Horse Canyon Section, Salinas Basin&amp;nbsp;

Abstract: Paleomagnetism Applied to the Monterey Formation of California: Results from the Horse Canyon Section, Salinas Basin&amp;nbsp;

A New Model for the Role of Salt in the Salina Basin of Southeast Mexico: ABSTRACT

A New Model for the Role of Salt in the Salina Basin of Southeast Mexico: ABSTRACT

Guild structure and aggradation pattern of Messinian Porites patch reefs: ecological succession and external environmental control (San Miguel de Salinas Basin, SE Spain)

Small and isolated Messinian patch reefs showing a typical internal succession and an oligospecific reef-building community are described from the western margin of the San Miguel de Salinas Basin (SE Spain). These thrived in a mixed carbonate -siliciclastic environment and are known from two different stratigraphic levels. The reef growth is characterized by a shallowing-upward sequence and can be subdivided into four divisions: reef debris zone; coralline algal zone; branching coral zone; and reef crest zone. This ecological succession. of Messinian reefs reflects an increasing water turbulence and the accommodation of the reef-building organisms to shallower-water settings, which is conditioned by its own upward growth. The start of reef growth is controlled by a reduced influx of terrigenous deposits, which derived from fan sediments reworked by waves. The reefs were killed by smothering with quartzose calcarenites. The low diversity of the reef-building community indicates an arrested ecological succession without climax stages, controlled by sedimentation rate and siliciclastic supply. A salinity increase can be excluded, because the reef-associated fauna indicates normal-marine conditions during reef growth. There is no evidence for subaerial exposure of the reefs during the formation of evaporites at the end of the Messinian.