Sidewall Core Data Research Articles

Integrated borehole image and rotary sidewall core data to support infrastructure-led appraisal: Capercaillie Field, Central North Sea

Abstract Quad 29 in the Central North Sea is a focus for bp, with a strategy to identify remaining hydrocarbon accumulations to tieback to existing infrastructure. Capercaillie was appraised in 2017 with well 29/04e-5 and sidetrack 29/04e-5z. A gas cap and thin oil rim were intersected within the siliciclastic Paleocene–Eocene Sele Formation. The reservoir sandstones were deposited in a deep marine setting by sediment-gravity flow processes. Within the context of a relatively detailed knowledge of the surrounding area, the reservoir data-operational risk-cost balance was addressed through acquisition of a full wireline logging suite, pressure data, latest-generation microresistivity images and targeted large-volume rotary sidewall cores (RSWCs), with the latter two favoured over whole core. Mature deepwater descriptive schemes were applied at the sidewall core (lithotype), bed (borehole image facies) and bed-stack (depositional package) scales. This hierarchical approach provided robust sedimentological data to underpin higher-order depositional models, which together were used as a framework to (1) constrain the reservoirs’ mineralogical and textural attributes, (2) establish the main controls on rock quality and (3) explain the resulting variations in porosity and permeability. This study demonstrates that the careful integration of data derived from the latest borehole imaging tools and large-volume RSWCs can be a successful means of characterizing reservoirs from a sedimentological, reservoir quality and reservoir architecture perspective in mature basins. Similar approaches to geological reservoir characterization in such settings are likely to be a common cornerstone of cost-effective development during the energy transition.

Scientific Results of the Hydrate-01 Stratigraphic Test Well Program, Western Prudhoe Bay Unit, Alaska North Slope

The United States Department of Energy, the MH21-S Research Consortium of Japan, and the United States Geological Survey are collaborating to enable gas hydrate scientific drilling and extended-duration reservoir response testing on the Alaska North Slope. To feasibly execute such a test, a location is required that is accessible from existing roads and gravel pads and that can be occupied without disrupting ongoing industry operations. A review of potential locations meeting these criteria determined the likely occurrence of gas hydrate in two fine-grained marginal-marine sands of Tertiary age in the vicinity of the inactive “Kuparuk State 7-11-12” exploration pad in the western Prudhoe Bay Unit (PBU). Existing well and seismic data for that site were insufficient to preclude the potential for free gas occurrence within the deeper (and most prospective) target sand. Therefore, with support from the PBU Working Interest Owners, Alaska Department of Natural Resources, and Petrotechnical Resources Alaska, the Hydrate-01 Stratigraphic Test Well (STW) was drilled in December 2018 to confirm the suitability of the site for future gas hydrate scientific testing. The Hydrate-01 well was successfully drilled to −3290 ft (1003 m) subsea vertical depth at a bottom hole location of approximately 900 ft (∼275 m) east of the surface location. The drilling program featured acquisition of a full suite of logging while drilling data, the collection of side-wall pressure cores, and the installation of distributed temperature and distributed acoustic sensor fiber-optic cables. The log data acquired confirmed the occurrence of gas hydrate at high saturation in two target sands. Integrated evaluation of log and sidewall core data provide petrophysical and geomechanical property information that allow for potential reservoir response to depressurization to be simulated. The deeper “B1 sand” is deemed to be most favorable for reservoir response testing as a result of confirmed gas hydrate occurrence in sediments of high intrinsic permeability, location within 100 ft (30 m) of the base of gas hydrate stability, and minimal risk for direct communication with permeable water-bearing (hydrate-free) zones. The shallower “D1 sand” provides a secondary target that is differentiated by colder in situ temperatures and the interpreted direct hydraulic communication to a lower section of non-hydrate-bearing, water-saturated sand. The Hydrate-01 log data also confirm the occurrence of at least one sub-seismic fault in close proximity to the B1 sand reservoir. To better image the distribution of the gas-hydrate-bearing reservoir sections and associated faults, a three-dimensional (3D) vertical seismic profile was conducted in early 2019 using the distributed acoustic sensors installed as part of the Hydrate-01 STW completion. Detailed two-dimensional (2D) and 3D geologic models have been constructed to enable numerical simulations to inform the planning for potential future scientific tests of reservoir response to depressurization at the site.

The correlation between low tectonic stress and the Appalachian Basin Quiet Zone

In order to assess the nature of the Appalachian Basin Quiet Zone (ABQZ), a region of low seismic activity, a minimum horizontal stress profile from sonic logs was calibrated using hydraulic fracture stress measurements in a well from McKean County, PA. The calibrated minimum horizontal stress profile that best fits with the hydraulic fracture stress data was established using an extended Eaton's model that treats rock as a transverse isotropic material with a vertical symmetry axis (TIV). To achieve a best fit, several assumptions are introduced: (1) a constant tectonically-induced elastic strain of εHmax = 3.3 × 10−4, (2) an anisotropic velocity model ANNIE approximation for shales, and (3) a bimodal pore pressure distribution with abnormally high pore pressure in the Marcellus gas shale. Other calibration methods assume an isotropic medium, a constant tectonic strain gradient corresponding to zero stress at ground surface, or constraints from sidewall core data to estimate stiffness constants. By testing four calibration methods, we find that stress profiles are affected by multiple factors, including the ratio of maximum tectonically-induced elastic strain over minimum tectonic strain, pore pressure in the Marcellus, Biot's coefficients, and elastic properties. Sensitivity analysis was conducted to analyze the influence of these parameters. Our stress profile is most influenced by pore pressure and tectonically-induced elastic strain while other factors had much smaller effects. Tectonically-included strain in the ABQZ is insufficient to achieve the critical stress necessary to induce frictional slip on favorably oriented faults in the sedimentary cover which presumably speaks to the lack of earthquakes in the basement of the ABQZ. However, induced earthquakes from deep disposal wells suggest that basement at the edge of the ABQZ may be decoupled from the sedimentary cover, in which case the cover has relaxed through a time-dependent deformation mechanism such as pressure solution creep.

Integrating core and wireline log datasets - a pathway to permeability from AvO seismic?

Improved reservoir modelling and simulation is sought by assigning permeability using AvO seismic. The integration of sidewall-core porosity and permeability with wireline logs represents one possible pathway for differentiating the seismic amplitude responses of different reservoir flow-unit facies. Two sand facies with differing porosity-permeability trends were defined in the reservoir interval of a Paleocene oil field in a shallow offshore clastic setting. Available sidewall-core data from several wells were added to their respective log datasets as discrete, depth-matched points and used to pinpoint the extraction of relevant log values corresponding to each point. The extracted Vp, Vs and density values enabled calculation of AI and Vp/Vs for each sample. Fluid substitutions using the Gassmann equations were then performed on points within the two sand facies. A statistical comparison of brine and oil porefill cases for each sand facies in this study showed a clear shift due to the hydrocarbon effect. However, only minor differences were observed in an AI-Vp/Vs cross-plot when the two sand facies with common porefill were overlain. Compositional similarity between the sand facies appears the most likely cause for the lack of significant difference in AvO response. Thin carbonates with high AI are also present in the reservoir interval and lateral variation in carbonate volume of as little as 5–10% would overprint the small differences observed between the sand facies. This method should be revisited for sand facies possessing greater compositional differences or where a larger porosity-permeability distinction between facies exists.

Pre-salt microbialites from the Campos Basin (offshore Brazil): image log facies, facies model and cyclicity in lacustrine carbonates

Abstract This study uses a borehole image log, supported by limited sidewall-core samples, and conventional wireline logs to erect facies and stratigraphic models for the Aptian pre-salt microbial carbonates (Macabu Formation (Fm)) of the southern Campos Basin, Brazil. This supports the widely held view that these reservoirs are very significant, unusual, partly microbial, and lacustrine in origin. This single-well study penetrates 220 m of microbialite facies from the pre-salt Lagoa Feia Group non-marine carbonates. Continuous borehole images, available sidewall-core data, and gamma-ray and sonic wireline logs are used to identify and characterize borehole image facies. These facies are interpreted to have formed in four lacustrine depositional environments: deep subaqueous, intermediate subaqueous, shallow subaqueous and subaerial. The borehole image facies commonly show shallowing-upward facies trends topped by emergent surfaces. Such trends are interpreted as metre-scale, high-frequency cycles that are grouped into lower order depositional sequences interpreted from the gamma-ray log. A Fischer plot of the high-frequency cycle suggests that the entire Macabu Fm is represented by a decrease in the accommodation space followed by increase in the accommodation space; consistent with this suggestion are trends in δ 18 O values from an adjacent well that indicate an initial trend of increased evaporation followed by increased freshwater inflow (lighter δ 18 O and thicker cycles).

Well Management: Use of Permanent Downhole Flowmeters for Pressure-Transient Analysis

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90316, "The Boris Field Well-Management Philosophy - The Application of Permanent Downhole Flowmeters to Pressure-Transient Analysis: An Integrated Approach," by E.J. Coludrovich, SPE, J.D. McFadden, SPE, and M.R. Palke, SPE, BHP Billiton; W.R. Roberts, SPE, Oilfield Production Consultants USA LLC; and L.J. Robson, SPE, BHP Billiton, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. Considering the large capital investments and returns for high-rate completions in overpressured unconsolidated-sandstone reservoirs, a testing method with defined objectives, designed to define acceptable risk levels for rates of individual completions, was necessary. Critical parameters, such as permeability and skin, are dynamic properties in these types of reservoirs and require frequent measurement. A program was implemented in the Boris field that relies on the use of permanent downhole pressure gauges and flowmeters. Field Description The Boris field comprises two wells in the Green Canyon area of the U.S. Gulf of Mexico with a water depth at the field of approximately 2,400 ft. First oil production from the Boris-1 well was in February 2003, and from the Boris-2 well in September 2003. Production from Boris-1 travels approximately 7,000 ft through a multi-phase flowline to a subsea manifold where production from Boris-2 is commingled with the stream. From the manifold, production travels approximately 5 miles to the Typhoon host facility. The 5-in. multiphase flowline has an erosional flow-rate limit of approximately 20,000 STB/D. Formation-pressure and performance data indicate that the Boris wells are hydrodynamically connected through a large aquifer that provides ample pressure support. Initially, the field was highly overpressured (0.75 psi/ft, or 10,400 psi) and relatively undersaturated, with a saturation pressure of approximately 6,700 psi. The crude is light and sweet with a gravity of 33°API, initial gas/oil ratio of 1,550 scf/STB, and in-situ viscosity of approximately 0.59 cp. No whole cores were taken from the Boris wells. Completion designs were based on empirical permeability estimates made with log and sidewall-core data. Average reservoir permeability of approximately 1 darcy was observed. Coupled with the low viscosity of the undersaturated oil, high initial pressure, and a relatively low skin factor achieved through careful completion planning, high-rate-potential wells were achieved as indicated by the initial productivity indices (PIs) of 25 and 30 STB/psi-D. Permanent downhole flowmeters (PDHFMs) were installed to assist production allocation and completion management. The use of PDHFMs was accepted by the U.S. Dept. of Interior Minerals Management Service for metering the commingled production. The completion interval consists of two clean-sand packages (B4 upper and B4 lower) separated by a shale interval that generally is 10 to 15 ft thick. The Boris-1 interval has 75 ft net thickness, and the Boris-2 has 115 ft net thickness. Initial pressure-gradient information indicated that the sands shared a common pressure regime and contact, and performance data do not clearly indicate whether the sands act isolated under producing conditions.

Quick Look Prospect Sizing -- Mississippi Canyon

Exploration and development of hydrocarbons in the deepwater Gulf of Mexico relies heavily on seismic expression of the targets and the resulting interpretation. Numerous seismic attributes can be extracted from the seismic data in order to assess the economic viability of a given prospect or discovery. Attributes are derived from a seismic wave’s response as it travels through the subsurface. The objective of this study is to determine the location and attitude of these reflections to infer geologic structure, stratigraphy, presence and extent of hydrocarbons, as they apply to estimating the range of Original Oil in Place (OOIP). A recent discovery in the Mississippi Canyon area was used as the test area to evaluate the utility of “quick look” analog data for initial prospect sizing/screening in the Tertiary amplitude play of southern Viosca Knoll — northern Mississippi Canyon areas. A Monte Carlo simulator provided for the distribution of OOIP estimates using inputted P10, means, and P90’s. Sensitivities, a product of the simulator, indicated that thickness and area were the drivers in initial OOIP estimates. The hydrocarbon accumulations in the study area occur predominantly in Middle Miocene turbidite deposits. Publicly available open hole well data and 3D seismic data provided the base information for the study. Petrophysical analysis of the well data, in the form of gross and net oil pay, provide the ground truth for comparison to seismic attributes. Basic seismic attributes included trough and peak amplitudes, composite amplitude, isochron, and the isochron/ composite amplitude product. These attributes were cross-plotted with the well data. Several strong correlations were apparent, with the net pay — isochron*composite amplitude being the highest having a .84 correlation coefficient (Fig. 1). Data for cross correlation were obtained from selected wells from Petronius, Tahoe, and Ram Powell Fields and were compared with seismic attributes over the discovery area. Well data from the discovery area were then compared to the predictive model in the order that they were drilled, revising the predictive model with subsequent wells as they were introduced. The tracking of OOIP estimates from the initial first look to the fourth well indicated significantly decreased variation in OOIP estimates with additional well data. The results of the study provided insight into future model refinements as well as appraisal strategies. The seismic survey utilized was part of a non-exclusive 3D survey using a 6000 meter cable length, 50 meter line spacing, 25 meter group intervals, and an eight second record length. The basic processing steps included spiking deconvolution, NMO, DMO, and inline/cross line migration. The majority of the open hole log data included the following digital information: gamma ray, resistivity, neutron and bulk density, and sonic logs. Additional data included sidewall core data and reservoir fluid information. The primary information extracted from a cursory petrophysical log analysis was net and gross sand thickness in the pay zones, which provided a basis for study of the region and comparison to seismic data. Further petrophysical attributes were analyzed and their range of uncertainty evaluated. However, those attributes were determined, by sensitivity analysis, to be of secondary importance at this stage of prospect sizing (Fig. 2). These petrophysical properties included changes in porosity, water saturation, grain size, cementation, and others. Reservoir fluid properties, such as gas/oil ratio, pressure, and formation volume factor, were also considered but were not determined to be vital to the sensitivities. From the seismic data, the peak amplitude, trough amplitude, and isochron thickness were recorded and analyzed for comparison. Tuning effects in the seismic data were investigated as part of the seismic issues associated within the analog fields and test area. Cross-referencing log (geologic data) with seismic data is essential for interpretation of reservoir potential in the Gulf of Mexico where class 1 amplitude anomalies are common, especially in some of the deepwater basins. Integrated reservoir studies require core descriptions, petrophysics, log interpretation, reservoir geophysics, reservoir flow simulation, and reservoir economics (Johann, 1997). In this area of the deepwater Gulf of Mexico seismic attributes, such as anomalously high amplitude, are reliable and a cost effective method of predicting subsurface lithology, reservoir continuity, and fluid composition. To this end, it is important to be aware of unusual lithologies that may cause anomalous amplitude responses such as condensed sections and ash beds by emphasizing the well to seismic tie. The ultimate goal of this study was to provide greater insight into initial prospect sizing/screening for field development and exploration. A Monte Carlo simulator provided the distribution of Original Oil in Place (OOIP) estimates. The predictive model was established using wells from regional fields and then applied to test area in the region to assess the method and the uncertainties involved with estimating OOIP. Once the regional data was

Deep-Water Reservoir Characterization Using High Resolution Formation MicroImager, Conventional and Sidewall Core Data, SEM and Thin Section Petrography from Mississippi Canyon 397 Field: ABSTRACT

Deep-Water Reservoir Characterization Using High Resolution Formation MicroImager, Conventional and Sidewall Core Data, SEM and Thin Section Petrography from Mississippi Canyon 397 Field: ABSTRACT

Controls on Permeability from Conventional Core Data in Unconsolidated Sands, Offshore Gulf of Mexico: ABSTRACT

One of the major shortcomings of many geologic models in attempting to characterize reservoirs is the uncertainty of permeability estimates. This uncertainty has been especially true in the offshore Gulf of Mexico where the cost of acquiring data is high. Most fields have no conventional core data; more often than not the geologist or petrophysicist has only wireline logs, occasionally supplemented by sidewall core data, to use in describing the reservoir. Conventional core data from 11 wells, taken in various parts of the Gulf of Mexico and from different depositional environments, were examined to develop a better correlation of porosity to permeability with rocks of different grain size and shaliness. Results from this study would allow an analyst without conventional core data to estimate permeability using porosity and grain size from sidewall core data.

Induced Spectroscopy: A Mineralogy-Lithology Well Log: ABSTRACT

Nuclear spectroscopy logging, specifically with the induced gamma-ray tool (GST), measures the relative yields of gamma rays resulting from interactions of neutrons with different elements (isotopes) present in downhole formations. The data are interpreted by associating the spectra of certain elements with sedimentary rocks which are typically dominated by the element (e.g., silicon = sandstone). The measured elemental yields are proportional to the volume fractions present in the rock formations. The yields are also proportional to some unknown values: effective neutron flux, concentration of selected elements in other sedimentary rocks, microscopic thermal neutron capture cross sections, and gamma-ray production and detection efficiencies. The effects of these unknowns can be minimized by laboratory calibration of yields in known formations or by comparison with whole or sidewall core data. With the above and some additional information (SARA-BAND, NGT), the well-site analysis or a more sophisticated computerized presentation yield volume fractions of effective porosity, sandstone, limestone, feldspar, and the total clay (shale) volume which may be further divided into volumes of clay porosity, illite, and chlorite. The resulting visual representation of these data becomes an invaluable aid to stratigraphic analysis. In a field study of tight gas shaly sandstones in the Cotton Valley Group (Upper Jurassic) in east Texas, the analysis not only described the clay mineralogy and lithology but also highlighted several important geologic features which are important in designing an efficient hydraulic fracturing program: genetic units of sedimentation, laminated and thick-bedded shales, hydrated shale beds, and zones of well-developed intergranular pore-filling (quartz or calcite) cements--all of which may be fracture-containment boundaries. End_of_Article - Last_Page 925------------

The Use of Sidewall Core Analysis in Formation Evaluation

Abstract Analytical techniques and procedures which permit accurate measurement of important physical properties and of fluid content of sidewall core samples as received in the laboratory are available. However, hole conditions prior to and during sampling affect the values as measured on the core samples. Also, the impact of the percussion sampler in the sampling process alters some of the physical characteristics of the sample. Comparisons of data on conventional and sidewall core samples and experience have shown the general direction of these effects. Normally, formations along the Gulf Coast have a greater productive capacity than the sidewall core sample data indicate. Water saturations associated with gas, condensate or oil production are greater in sidewall than in conventional core samples. Sidewall core data are valuable as exploratory aids, but data from conventional or wireline cores are generally required for evaluating recoverable reserves, the distribution of reservoir fluids and formation flow characteristics. Sidewall core data usually establish the presence or absence of hydrocarbon content and indicate the probable type of production. Measured permeability and porosity values indicate productive capacity. The data show gas-oil and water-oil contacts. Sidewall sample data are particularly valuable as a basis for "calibrating" electrical log data. They are used to check lithology changes indicated by log data, and they permit evaluation of thin and stray sands. Sidewall core samples probably provide the most reliable data normally obtained on "dirty" or ashy sand zones which show low resistivity on the electrical logs, on sand sections drilled with high-salt-content muds and on shallow bentonitic sands containing fresh water. Consideration of both sidewall core analysis data and electrical log data together increases the value of each. In many instances, it is necessary to consider both types of data in arriving at a correct interpretation. Greatest value can be obtained from the sidewall core data if the analyst has an electrical log of the zone as a guide for general formation characteristics and for zoning the various samples.