Section Of Well Research Articles

Similarities and Differences in Mesozoic Strata in Mexico and the US Gulf Coast

Mexican Mesozoic strata along the Gulf of Mexico are very similar to Jurassic and Cretaceous sections in wells in Arkansas, Louisiana, and East Texas. The oldest sedimentary rocks (Eagle Mills-Huizachal alluvium) are redbeds of Triassic age, followed by Middle Jurassic basin-centered evaporites, which are unconformably overlain by transgressive Late Jurassic limestones and shales. The Oxfordian facies pattern is as yet not well known in the subsurface, but the Kimmeridgian has a wide distribution of oolitic and reefy shoal facies around former high areas. These facies change basinward to dark pelagic shales and limestones of the San Andres to Taman formations. Similarly, in the Ark-La-Tex area, Smackover and Haynesville carbonates grade downdip to argillaceous organic-rich sediments. This whole succession is overlain by a blanket of Tithonian sediments of the Pimienta Formation. This unit has been studied in detail by the authors from nearly 100 cores throughout this region; it consists of organic-rich argillaceous lime mudstones and calcareous shales and furnishes a rich source for the giant oil fields of the Campeche Bank. The tremendously thick Cretaceous section which follows is mostly carbonate, built on Jurassic basement ridges of Early Mesozoic horsts and grabens. In contrast to the above stratigraphic similarities, structure is much more complex in southeastern Mexico than along the northern Gulf rim. Pacific coast plate interactions caused island arcs to form along the western continental margin of Mexico and produced an eastward movement of the Caribbean plate. This was accompanied by Miocene and Laramide folding and northwest-directed faulting in the Early Mesozoic. All of this complicates and compounds diagenetic effects in both carbonates and clastics and makes the deciphering of fracture patterns very important. This may be compared to the simpler structural trends of the Ark-La-Tex area where extensional fault trends and salt domes constitute the major structural features. GULF COAST ASSOCIATION OF GEOLOGICAL SOCIETIES TRANSACTIONS VOLUME LI, 2001 412

Application of neural networks to identify lithofacies from well logs

Neural networks are physical cellular systems that can acquire, store, and utilise knowledge obtained by experience. They have a number of performance characteristics in common with biological neural networks or the human brain. They can simulate the nervous systems of living animals that work differently from conventional computing and analyse, compute and solve complex practical problems using computers. Studies show that neural networks can be used to solve a great number of practical problems that occur in modelling, predictions, assessments, recognition, and image processing. Especially, neural networks are suitable for application to problems where some results are known but the manner in which these results can be achieved is not known or is difficult to implement; or where the results themselves are not known.Lithofacies are, by definition, determined directly from the rock body, either an outcrop or conventional core. However, in subsurface studies it is important to be able to estimate the lithofacies of uncored wells or sections of wells. This is commonly done in a somewhat subjective manner using a wireline-log suite, and often using only the gamma-ray log. This paper presents an application of neural networking to identify lithofacies from wireline logs in a lithologically complex formation. The methodology provides a considerably more thorough, consistent, and less subjective means by which to estimate lithofacies, and indeed depositional facies, than is currently in use. Only conventional wireline-logs were available in this study. Nonetheless, it was possible to establish an identification network of lithofacies by integrating error back propagation and self-organising mapping algorithms. This network was applied to identify lithofacies in six wells. The results indicate that, given a reliable training set which is provided from a detailed lithofacies analysis of conventional cores within the formation under study, it is possible to estimate lithofacies from conventional well logs by means of neural network techniques.

Addressing BHA Whirl: The Culprit in Mobile Bay

Summary Lateral bottomhole assembly (BHA) vibration, more particularly BHA whirl, is known to be an extremely destructive downhole phenomenon, the occurrence of which is thought to be one of the primary contributing factors to drillstring failure in Mobile Bay. Unfortunately, indications that BHA whirl is occurring while drilling are rarely evident from conventional surface measurements, especially in deeper sections of wells. Without knowledge of the existence of a problem, avoidance is almost impossible. For the first time, the potential for the surface identification of BHA whirl is thought to be possible through the measurement of drillstring vibrations. We present data from a well in Mobile Bay where surface vibration measurement and monitoring was conducted while drilling the 12¼-in. hole section. Axial and torsional data demonstrate characteristics thought to be indicative of BHA whirl, which is shown to be associated with accelerated drillstring fatigue, as demonstrated by BHA failures. Various approaches were taken to eliminate the whirl once the phenomenon was recognized, with ultimate success in that the incidence of BHA failure was reduced. Prewell planning and improved drilling practices resulted in the use of fewer bits and reduced drilling time over the same section on wells previously drilled in the area.

Bottom-hole vibration damper with a sheathed variable-rigidity elastic element

Oil and gas well drilling under difficult conditions and the drilling of horizontal sections of oil wells impose new requirements on the components of the drill-string bottom assembly (DSBA). One such requirement is longitudinal stability of the DSBA in the case of action of optimal loads. With limited dimensions of the transverse section of the well, this can be achieved only by reducing the length of the DSBA. One of the elements of the DSBA is the bottom-hole vibration damper. In current practice, the DSBA is made up with drill vibration dampers that are quite long, designed for a specific load. This makes it difficult to use vibration dampers in DSBA intended for drilling under difficult conditions; also, this limitation makes it necessary to stock a greater number of different vibration dampers. In order to eliminate these problems, a bottom-hole vibration damper with a sheathed variable-rigidity elastic element was developed that has been tested successfully in oil fields of the Ukrneft` Production Association. The field tests not only confirmed the reliability and effectiveness of operation of these vibration dampers under difficult drilling conditions, but also pointed out ways in which they could be improved.

Missing Stratigraphic Sections in Tertiary Sandstone Reservoirs of the Gulf Coast: Faults or Unconformities and Implications for Development Strategies: ABSTRACT

ABSTRACT Missing section identified by log correlation in Gulf Coast boreholes is typically interpreted as displacement by downward movement along the upper surface of a growth fault. A common interpretation strategy is to link wells containing missing section with a growth fault having a curvilinear geometry in map view. We present here an alternative possibility: section missing because of erosion. This interpretation has a very different geometry and results in alternative implications for compartmentalization in stacked sandstone/shale reservoirs. Missing stratigraphic section in the F39 Frio reservoir of Lavaca Bay field, an Oligocene barrier/strandplain reservoir in Calhoun County, Texas, has been attributed to growth faulting. The geometry of missing sections in wells in this reservoir is complex, however, and the standard fault interpretation results in an unusual and geologically unlikely structural configuration. A dipmeter log from a key well in this reservoir indicates a sharp boundary at the depth of missing section and a distinct change in northwest dip from 8° above to 14° below. The map-view geometry of missing section defines two subcircular areas of erosion. These features are interpreted to have formed by local uplift due to shale diapirism and concomitant erosion of an overlying sandstone, which was deposited as a widespread tabular strandplain. The current structural crest of the field occurs between the two eroded paleohighs. Two wells in the present structural crest penetrated thick reservoir sandstone and have yielded approximately 20 percent of the cumulative production from this reservoir. Distinguishing missing section caused by erosional unconformities from that caused by growth faulting has three implications for reservoir development and resource assessment: (1) compartments bounded by faults can contain sandstones of nearly uniform reservoir properties throughout, whereas compartments caused by erosion will contain thin sandstones along the margins, (2) interpreting compartment boundaries as faults will result in very different compartment shapes than would result from the unconformity interpretation, and (3) misinterpreting missing section can lead to miscorrelation of productive zones in stacked reservoirs and, thus, to incorrect estimations of remaining resources. End_of_Record - Last_Page 767-------

Variation in organic matter quality and maturity in Draupne formation source rocks from the Oseberg field region, offshore Norway

Detailed characterization of the kerogens from closely spaced samples from the Draupne Formation penetrated by two wells, A and B, in the Oseberg Field region has been carried out by geochemical and petrographic methods. For selected samples the C 15-hydrocarbon fraction has been examined by GC and GC/MS. Petrographic analyses by transmitted light and UV excitation fluorescence methods demonstrate that the organic matter in all samples from both wells consists predominantly of amorphous material. Total organic carbon contents and hydrogen indices indicate an overall trend of decreasing kerogen quality with increasing depth for the Draupne Formation in well A. Similar data for samples from well B demonstrated generally inferior kerogen quality. Maturation level for the organic matter of the Draupne Formation in well A is slightly higher than that in well B, while both Draupne sections are within the limits for an immature source rock with a type II kerogen. GC- and GC-MS-analysis showed that the samples from well B were enriched in lighter hydrocarbons as compared to samples from well A. It is suggested that this may be due to minor staining of the former samples by migrated light hydrocarbons from the underlying Upper Jurassic sandstone reservoir. A correlation between the two sections of Draupne Formation based on organic facies characteristics indicate a general correspondance between the lowermost part of the section in well A and the section in well B.

Maturity of organic matter and migration of hydrocarbons in two Alaskan North Slope wells

Plots of T max and production index (P.I.) for seven Alaskan North Slope wells suggest that samples from the Ikpikpuk well are optimal for examination of thermal maturity and the Seabee well for migrational geochemical trends at all maturity levels. Vitrinite reflectance profiles for the two wells are identical and reach maximum values of 2.5% in the deepest rock units. Pyrolysis P1/org C, T max, and P.I. values all behave “normally” in Ikpikpuk but for Seabee show generally lower (by about 60°C) T max values and higher and more scattered P1/org C and P.I. values. Sorbed light hydrocarbon ratios including C2/C3; ic4/ nC4; iC5/ nC5; 22DMB/ nC6; MCP/benz; benz/tol; paraffin indexes 1 and 2 and C1/(C1 + C2 + C3) are compared for both wells. Light hydrocarbon data for Ikpikpuk generally shows smooth changes expected for maturation across the Kingak shale and Shublik formation with increasing paraffin indexes 1 and 2; decreasing MCP/enz; increasing benz/tol; increasing C1/(C1 + C2 + C3); and a spike in 22DMP/ nC6 at the bottom of the over-mature Sadlerochit sandstone. These ratios are consistent with some localized lateral migration at the bottom of the Sadlerochit Group sandstone and at the top of the pebble shale unit. In contrast, Seabee ratios were very different and showed no particular trends with depth, although some increase in proportions of methane and benzene are observable in the deepest sections of the well. The ratios of pyrolyzable C1/(C1 + C2 + C3) for the Ikpikpuk well were similar to those for the generated sorbed gases within for the catagentic and post mature sections of the well. Seabee showed pyrolyzable C1/(C1 + C2 + C3) ratios similar to those from Ikpikpuk except for a less pronounced bottom hole increase in the ratio. Migration phenomena with preferential retention of polar asphalts or pyrobitumens in strata through which or from which migration has occurred are postulated to be the cause of a low temperature P2 shoulder often observed in and below the catagenic zones of Ikpikpuk. GC/MS data of pyrolyzable material shows that maturation causes a decrease in alkane and alkene pyrolysis products as compared to aromatic and heterocyclic compounds. This low temperature shoulder appears to become the predominant P2 peak in sections of other wells, such as Seabee, which are extensively influenced by migration.