Wireline Data Research Articles

ABSTRACT: Real-Time Tracer Monitoring of Reservoir Stimulation Procedures via Electronic Wireline and Telemetry Data Transmission

ABSTRACT: Real-Time Tracer Monitoring of Reservoir Stimulation Procedures via Electronic Wireline and Telemetry Data Transmission

Litho-flow facies prediction in an alluvial fan/fluvial system, central North Sea

An existing generic facies scheme consisting of a channel, sheetflood and floodplain facies was available from the cored wells. Bivariate and multivariate analysis of various wireline and core data indicated that each generic facies exhibits wide variations and significant petrophysical overlap with other facies. This scheme cannot therefore reliably be applied using wireline data, negating its application in uncored intervals through discriminant analysis. Due to the large variation in porosity and permeability of each facies, the existing scheme does not permit adequate determination of the probable reservoir performance of the sediments. In order to address these problems a new "litho-flow" facies scheme has been constructed which can clearly be identified from wireline data thereby enabling it to be reliably extended beyond cored intervals. Each facies in the scheme exhibits a discrete range in porosity and permeability by which the probable flow characteristics of the sediments can be assessed and has successfully been used by reservoir engineers as input to a probabilistic reservoir modelling package. Finally, the predicted facies are valid in terms of the environment of deposition, assisting geologists in the correlation of units between wells for the establishment of a depositional model. The new facies scheme was formulated from a careful selection and processing of data to achieve the above. This included core descriptions, core porosity and permeability measurements, mineral volume analysis and porosity estimation from wireline data, permeability predictions and electrofacies from cluster analysis.

Well log stacking: a new technique to improve laterial prediction and sequence stratigraphic interpretation with wireline data

The correlation of wireline (well log) data forms an essential part of the interpretation of geological strata in sedimentary basins. The technique usually involves matching by eye the log curves produced from digitally sampled data in one well with those from one or more adjacent wells. Correlation is used primarily to access the lateral extent of rock bodies in the subsurface. However, it is a highly subjective process and is hampered by the difficulty in visually discriminating between non-geological noise, local geological trends and regional geological trends when comparing a number of logs. Variations in the thickness of an interval or differences in the data acquisition between wells compound these problems. Correlation is also constrained by the number and spacing of the wells in question. Thus it is hard to determine what is happening between widely separate wells whilst it is difficult to interpret more than a few log curves at one time due to their complexity. The solution is typically to concentrate on only a few obvious features such as a minimum or maximum peak or the diagnostic response of a specific rock type and to make some simple assumptions as to the lateral extent of other features. Even where additional geological data such as biostratigraphic or core information are available, it is often impossible to be sure that a log pattern in one well is not coincidentally similar to that in another well and regional geological trends will often be disguised by higher amplitude, shorter wavelength local variations. As a consequence of the problems mentioned above, the methodology used in correlating well logs is typically rather arbitrary and is unlikely to use all the data to full advantage. Hence it is difficult to objectively evaluate the validity or confidence level in correlations when assessing, for example, whether reservoirs are likely to be connected across a field or what the chance are of finding a known reservoir in a new well. The subject of this paper is a new automated tool which aims to improve on traditional manual correlation techniques by incorporating all equivalent data from every relevant well into a single log curve. The process suppresses the effect that local variations have on the log signal and enhances the regional response.

A sleeping giant awakened; further development of the Seria Field, Brunei Darussalam, after almost 70 years of production

The Seria Field was discovered in 1929. Cumulative oil production reached 164X10 6 m 3 (end 1996), approximately 34% of known in-place volumes. A maximum oil production level of 18 780 m 3 /d in 1956 has since declined to 2800 m 3 /d. Most of the more easily recoverable oil has now been produced. Undeveloped oil is concentrated in economically marginal accumulations for which simple subsurface models are an inadequate basis on which to plan further development activities. Instead, dynamic simulation of detailed computer-generated 3D reservoir models is required to optimize reservoir management and evaluate potential development options. 3D seismic data are used to assess undrilled closures and new exploration plays resulting in the development of new hydrocarbon accumulations. Amplitude analysis combined with GST/RST logging has identified areas of unswept oil within the field. Detailed 3D reservoir geological models integrating sequence stratigraphic concepts with reappraisal of core and wireline data are being built using Unix workstations. The models incorporate the results of advanced petrophysical techniques, such as image analysis and resistivity inversion, to quantify net sand, porosity and saturation, and NMR to provide information on moveable oil and permeability. The model forms the input to advanced reservoir simulators where multiple sensitivities can be tested to determine the optimum placement of new wells. Advances in drilling technology have led to the use of horizontal and multi-lateral wells to give the increased productivity necessary for commercial success of such marginal developments. Concurrent engineering effort has led to the field's facilities being rationalized to improve efficiency and reduce costs and the designing of re-usable well jackets for the shallow offshore part of Seria.

Well log stacking: a new technique to improve lateral prediction and sequence stratigraphic interpretation with wireline data

Well log stacking: a new technique to improve lateral prediction and sequence stratigraphic interpretation with wireline data

Reservoir and Production Analysis of the K40 Sand, South Timbalier 295, Offshore Louisiana, with Comparison to Time-Lapse (4-D) Seismic Results

Reservoir and production characteristics of the K40 sand (South Timbalier Block 295, offshore Louisiana) are used to track the oil-water contact as it moved vertically 80 m between 1988 and 1994. This zone of water sweep is associated with a strong decrease in seismic amplitudes observed from comparison of 3-D (three-dimensional) seismic curves acquired before hydrocarbon production (1988) and during production (1994). The Pliocene K40 sand is an overpressured (0.80 psi/ft) turbidite reservoir deposited in a slope minibasin. Wireline and seismic data are used to develop a geologic model for this reservoir. This analysis, combined with production history and log data, indicates that relatively uniform water sweep was effectively imaged by time-lapse (4-D) seismic over most of the reservoir. The lack of seismic dimming in some parts of the reservoir is attributed to poor drainage of low-permeability lithofacies. In addition, it may not be possible to image drainage of reservoir zones with less than 10 m of original net pay with these data. These results illustrate the potential of time-lapse seismic analysis for illuminating the dynamic behavior of producing reservoirs and indicate that preproduction seismic surveys, not originally intended for use in time-lapse (4-D) seismic analysis, have value as baselines for seismic monitoring studies.

ADVANCES IN WIRELINE DATA ACQUISITION IN SYNTHETIC-BASED MUD SYSTEMS AND STRATEGIES FOR IMPROVED FORMATION EVALUATION

With the growth in popularity of synthetic-based mud (SBM) systems in Australia, and the emergence of more advanced wireline logging tools, there is an expectation that better hole conditions will give rise to better value- for-money evaluation programs. This is certainly true from the drilling cost perspective, where a logging job can be completed without need for 'wiper' trips to recondition the hole. However, in order to extract maximum value from the latest generation of logging tools, careful attention needs to be applied to the formation evaluation program.There have been some unexpected results from the wireline data quality viewpoint, with some positive results mixed with outcomes that fell below expectation, both linked to the complex nature of the synthetic-based mud recipes. Contrary to intuition, good quality electrical images may be obtained in synthetic-based muds, and some mud additives used to stop filtrate loss can seriously degrade the quality of acoustic images that are traditionally run in SBMs. Nuclear Magnetic Resonance works well in SBMs, especially where invasion is kept to a minimum. Holes drilled with SBMs do not normally display borehole ellipticity, which may be used to infer tectonic stress directions. However, oriented cross dipole shear-weave logging is able to detect azimuthal anisotropy, which may be related to tectonic stress, in holes with a circular profile.There are trade-offs using different SBM recipes, which will impact on formation evaluation programs. Close consultation with the logging contractor and mud company, as far ahead of the drilling of the well as possible is recommended to ensure a satisfactory outcome.

Prediction of Petrophysical Parameters Based on Digital Video Core Images

Summary Core-slab photography is a common way to document geological information from cores. Past practice has been to photograph core slabs with ordinary cameras that produce paper photographs. The presented method retrieves petrophysical properties from high-resolution digital video core images. The procedures described in this work are based on video images (standard RIO/B camera) of cores taken with a digital recording system. The system is able to record in both visible and UV light at different illumination angles, store images, compress/decompress images, and display one or several images as a continuous long core. The seamless core image is marked with depth scale and can be scrolled, scaled, and zoomed. Facilities for correlation with other related data, such as wireline logs, discrete core data, and microscopy images, are also included in the system. We used homogenous dry core plugs from three North Sea oil fields in this work. We recorded images of plug surface, together with conventional core-analysis data (i.e., porosity, gas permeability, average grain size, and mineralogy). The new method is based on processed digital images: light/shadow patterns are obtained by use of asymmetric, low-angle illumination in the green channel. Texture spectra of the rock material are obtained by dedicated image-analytical processing of these gray-scale images and by detecting textural features by use of a unique set of specially designed texture filters. We then calibrate these spectra with respect to measured petrophysical parameters by use of multivariate calibration [partial least squares (PLS)-regression]. Multivariate calibration is based on a set of representative training images, selected to span representative ranges of the intensive petrophysical parameters being modeled. On the basis of this calibration model, similar gray-level video images from new, unknown core sections (with geologically similar fades) are used to estimate properties of the core material by PLS-prediction. In this study it has been possible to model porosity, gas permeability, and average grain size (ORZ) of different formations with a relatively high accuracy and precision. PLS-modeling/-prediction is a strict empirical calibration procedure. The present method is critically dependent upon a thorough, geologically well-documented training data set. Results show that the method is capable of predicting a continuous log of these three petro-physical parameters based on core images calibrated against a set of routine laboratory core-analysis data taken at discrete intervals for a particular formation. The advantages of the new method are rapid and cost-efficient methods for prediction of petrophysical parameters, particularly from slim cores, and improved integration of geological records with wireline data. The method is proposed to be included in future routine laboratory core analysis studies because of its low cost and ability to predict values continuously along the core.

Dolomite cement distribution in a sandstone from core and wireline data: the Triassic fluvial Chaunoy Formation, Paris Basin

Abstract The distribution of mineral cements in oil fields is critical to the spatial variation of porosity and permeability. The distribution of dolomite cement within fluvial Triassic Chaunoy sandstones in the Paris Basin was studied using core description, petrography, core analysis (porosity and permeability), wireline data interpreted to give mineralogy, porosity and permeability data and geochemical data. Petrographic analysis revealed that dolomite and quartz cements are the main diagenetic minerals. Using sonic transit time, density and neutron porosity log, the overall proportions of quartz, dolomite and shale as well as porosity for each depth interval could be resolved. Petrographic and core analysis data showed that permeability could be calculated from wireline-derived porosity and mineralogy data. There is excellent correlation between core analysis porosity and permeability and their wireline-derived equivalents. There is also excellent correlation between wireline-derived mineralogy data and quantitative petrographic mineralogy data. The wireline-derived mineralogy data show that dolomite is preferentially concentrated at the tops of most sand bodies. Porosity and permeability are consequently lowest at the tops of individual sand bodies due to the localized dolomite cement. There are a number of potential causes for this distribution pattern although geochemical and petrographic data showed that a combination of early pedogenetic dolomite cementation and later recrystallization, possibly due to an influx of organically-derived CO 2 , are most likely.

Quartz cement volumes across oil-water contacts in oil fields from petrography and wireline logs: preliminary results from the Magnus Field, Northern North Sea

Abstract Quartz cement is a significant porosity-reducing mineral cement in many sandstones and thus affects economically significant reserves calculations and flow-rate (through its effect on permeability). The presence of oil in a reservoir is commonly assumed to retard quartz cement precipitation and thus early oil emplacement is often thought to preserve porosity and permeability. A combined petrographic and wireline log approach was utilized to investigate whether quartz cement volumes and the total quantity of quartz do indeed vary across the oil-water contact in a sandstone reservoir. Thin-section point-count data and bulk density, neutron porosity and sonic transit time wireline log data were obtained across the oil-water contact from three wells in the Magnus field, an Upper Jurassic turbidite sandstone reservoir in the Northern North Sea. Reported oil filled inclusions in quartz overgrowths in this reservoir show that quartz cementation occurred either during or after oil emplacement. Point count data were used to determine quartz cement and total quartz volumes across the oil-water contact, whilst wireline data were transformed to reveal the total quantity of quartz across the oil-water contact. Preliminary results seem to show that the volume of quartz cement and the total volume of quartz show little or no variation across the oil-water contact. These data seem to imply that the presence of oil in the reservoir had no appreciable effect on the component processes involved in quartz cementation in this field: a paradox that will be further investigated.

The acquisition of geophysical wireline logging data as part of the UK Nirex Ltd investigations of a potential radioactive waste repository at Sellafield, Cumbria

Abstract UK Nirex Ltd is currently carrying out an investigation of the Sellafield area of West Cumbria to assess the potential for a radioactive waste repository. The investigation includes the drilling of deep boreholes to acquire data for site characterization and safety assessment. Geophysical wireline logging takes place at intervals within the drilling schedule and includes the use of the latest ‘state-of-the-art’ technology. Acquisition is carried out under a rigorous quality control regime in order to generate quality assured data sets which are then processed to generate additional information. Wireline data is used extensively in the acquisition programme and in the verification of results. The data is also used by interpretation teams to assist in geological and hydrogeological interpretation and rock mass assessment.

Geomorphology: A Key to Filling Gaps and Increasing Realism in Reservoir Descriptions: ABSTRACT

Combining core and wireline data with geomorphic analogs facilitates the quantification of geologic information for the numerical characterization of subsurface strata. Traditional three-dimensional geologic descriptions are limited by one- and two-dimensional data sources (outcrop or well data). Geomorphic analyses of fluvio-deltaic systems reveal log-normal distributions of discrete depositional environments. These provide statistical constraints for conditioning the area (X and Y dimensions), shape, placement, and preferred orientation(s) of geologic facies in three-dimensional models. Accurate stratigraphic and facies-association representations built from subsurface and analog data are integral parts of geologic modeling. Seismic, outcrop, and vertically oriented well data provide structural and chronostratigraphic information. Moreover, core and wireline-log data give lithofacies; type and thickness (Z dimension), in addition to petrophysical trends. The distribution of facies in the X and Y directions (between wells) is realistically accomplished by using geomorphic guidelines to distribute lithofacies or facies-associations as three-dimensional objects. Furthermore, geomorphic analogs aid the distribution of a lithofacies within a facies association. This is beneficial where individual beds contain permeability extreme. Given, a relationship between facies and permeability, a three-dimensional rendition of facies becomes a proxy for reservoir quality. Geomorphic data from appropriate modern fluvio-deltaic analogs are linked with core and wireline-log data tomore » render conditioned, three-dimensional, geologic models. Model accuracy relies upon bed-thickness and chronostratigraphic constraints imposed by cores and stratigraphic correlations, as well as, the lateral extent of facies associations governed by geomorphology.« less

Shear and Compressional Velocities of Overpressured Shales, Louisiana Offshore: Effects of Lithology and Effective Stress: ABSTRACT

Wireline and core data show how shear and compressional velocities (V[sub s] and V[sub p]) of overpressured shales from the Eugene Island Block 330 Field (Offshore Gulf of Mexico) are affected by lithology, and effective stress. From 2.1 to 2.5 km depth, V[sub p] ranges from 1750 to 2600 m/s, V[sub s] ranges from 500 to 1100 m/s, and Poisson's ratio is about 0.44. Plotting V[sub p] against V[sub s] for shales shows a strong linear trend that is close to, but different from previously defined trends. For sands, 3 different fields are distinguishable, and these can be related to fluid content, interbedding and shaliness of the sands. Compressional velocities for these deposits are primarily a function of porosity, shaliness (V[sub sh]) and effective stress. For narrow ranges of effective stress, V[sub p] increases with V[sub sh] to about V[sub sh] - 30 %, then V[sub p] decreases with increasing shaliness. As effective stress increases, V[sub p] increases for all lithologies. The trends seen in the data from these overpressured sediments also fit sediments from the stratigraphically higher, normally compacting (hydrostatically pressured) part of the section in a nearby well. About 3/4 of the overpressure is due to compaction disequilibrium,more » and the remainder is due to some other mechanism. The reduction in effective stress due to this other cause of overpressure would not have significantly affected V[sub p]. Since there is a good linear relationship between V[sub p] and V[sub s], V[sub s] would not have been significantly affected either. This raises the possibility that the high Poisson's ratio for these shales is an inherited function of depositional processes (undercompaction due to rapid fine-grained sediment accumulation).« less

Wireline shear and AVO modeling: Application to AVO investigations of the Tertiary, U.K. Central North Sea

Numerous examples exist in the literature of the successes and failures of the application of amplitude variation with offset (AVO) “gas effect” theory in hydrocarbon exploration. The acquisition of wireline and VSP shear data is considered critical information for accurate calibration, quantification, modeling, and successful application of AVO analysis techniques in a particular geologic environment. Wireline compressional, wireline dipole shear, well vertical seismic profiling (VSP), and surface seismic data are used to investigate the AVO behavior of the major lithologic boundaries and hydrocarbon bearing zones. Within the study area, lithologic boundaries produce significant AVO anomalies that may be easily confused with Class III AVO gas effect. In addition, the principal economic target, oil bearing sands, does not appear to produce AVO gas effect anomalies; although a Class III AVO gas effect response is observed when as little as 2 m of free gas is present at the top of the reservoir. Confirmation of an (Class I, II, or III) AVO gas effect in these Tertiary sands can be significant for detecting and delineating reservoirs; however, excessive emphasis on the importance of AVO gas effect, or high amplitudes on relative amplitude seismic sections, will result in an underestimate of (oil) hydrocarbon potential within the region.

A COMPARISON OF LABORATORY AND FIELD MEASUREMENTS OF P‐WAVE ANISOTROPY1

AbstractP‐wave velocity anisotropy determined from a cross‐hole survey at the Imperial College borehole test site compares favourably with that measured in the laboratory on core from the holes. The holes penetrate a layered sequence of sandstones, shales and carbonates of the Namurian Upper Limestone Group. The Laboratory measurements of the vertical and horizontal velocities of core samples indicate that the shales exhibit P‐wave anisotropies of over 20% but that the sandstones and limestones are only slightly anisotropic. These discrete measurements have been used in combination with wireline data to produce a log of P‐wave anisotropy. Including the anisotropic information vastly improves the match between observed and synthetic traveltimes from the cross‐hole data set. This implies that there is little frequency dependence of intrinsic P‐wave anisotropy.Inversion of the cross‐hole traveltimes highlights the need for good angular coverage in order to resolve the anisotropy parameters. The observed P‐wave anisotropy of the field data is due to the combined effect of sedimentary layering and the intrinsic anisotropy of the rocks. The intrinsic anisotropy is found to be the dominant factor.

Digitizing Rocks? Standardizing the Geological Description Process Using Workstations

The preservation of geological knowledge in a standardized digital form presents a challenge. Data sources, inherently fuzzy, range in scale from the macroscopic (e.g., outcrop) through the mesoscopic (e.g., hand-specimen) core and sidewall core, to the microscopic (e.g., drill cuttings, thin sections, and microfossils). Each scale change results in increased heterogeneity and potentially contradictory data and the providers of such data may vary in experience level. To address these issues with respect to cores and drill cuttings, a geological description workstation has been developed and is undergoing field trials. Over 1000 carefully defined geological attributes are currently available within a depth-indexed, relational database. Attributes are stored in digital form, allowing multiple users to select familiar usage (e.g., diabase vs. dolerite). Data can be entered in one language and retrieved in other languages. The database structure allow groupings of similar elements (e.g., rhyolites in acidic, igneous or volcanics subgroups or the igneous rock group) permitting different uses to analyze details appropriate to the scale of the usage. Data entry uses a graphical user interface, allowing the geologist to make quick, logical selections in a standardized or custom-built format with extensive menus, on-screen graphics and help screens available. Description ranges are permissible.more » Entries for lithology, petrology, structures (sedimentary, organic and deformational), reservoir characteristics (porosity and hydrocarbon shows), and macrofossils are available. Sampling points for thin sections, core analysis, geochemistry, or micropaleontology studies are also recorded. Using digital data storage, geological logs using graphical, alphanumeric and symbolic depictions are possible. Data can be integrated with drilling and mud gas data, MWD and wireline data and off well-site analyses to produced composite formation evaluation logs and interpretational crossplots.« less

The Answer: The Definitive Formation Evaluation Log Through Well-Site Information Management

Formation evaluation data are currently available at the well site from many different service sources, such as drilling and geological surveillance, formation evaluation measurement while drilling (FE-MWD), and wireline logging. Additional critical data are available from the mud engineer and drilling supervisors. Traditionally, their outputs have been presented inconsistently in a variety of formats, at different scales and data intervals, and during and after drilling the well. The well-site use of an information management system permits a continuous process of integrating and presenting all data as the data become available. The FE-MWD service provides continuous measurements of formation properties, which are confirmed by geological logging of the cuttings. Formation fluids interpretation from FE-MWD are qualified by mud gas analysis and hydrocarbon show evaluation. Uncertainties associated with the individual data sets, i.e., surface vs. downhole, are dispelled when the data are presented together. Drilling data allows the driller to optimize rig, BHA, and bit performance. Daily reporting is simplified through the rapid production of composite logs in specialized formats and scales. This permits the geologist and petroleum engineer to see at a glance all information necessary for decision making. Futhermore, the ability to combine offset well data with current well datamore » allows for better anticipation of reservoirs, hole problems, etc. The subsequent addition of wireline data allows for a verification of the while-drilling data quality and finalizes the data set. Subsequent workstation data manipulation can proceed with final depth matching and merging to standardized or customized log formats. Because data have been accumulated and verified on an ongoing basis by the well-site team, the final well report is rapid. Furthermore, the main advantage is the speedy production of the definitive end of the well [open quotes]composite log.[close quotes]« less

VSP measurement of shear‐wave velocities in consolidated and poorly consolidated formations

Mode conversion in the subsurface can generate shear waves with sufficient amplitude so that they can be used to measure shear‐wave propagation effects. Significant mode conversion can occur even at near vertical incidence if there is sufficient contrast in Poisson’s ratio across the interface. This can be exploited to measure shear‐wave velocities in the underlying section in the course of vertical seismic profile (VSP) acquisition. The technique is effective even in poorly consolidated formations with low shear‐wave velocities where sonic waveform logging fails. Where shear‐wave velocity data are available from sonic waveform logs, the VSP data can be used to verify the wireline data and to calibrate these data to seismic frequencies. The technique is illustrated with a case study from the North Slope, Alaska, in which several shear‐wave events are observed propagating downward through the subsurface. The seismic source is a vertical‐motion vibrator; shear waves are generated via mode conversion in the subsurface and also radiated from the source at the surface, and they are observed with both far‐ and near‐source offsets. The shear‐wave events are strong even on the near‐offset data, which is attributed to the contrast in Poisson’s ratio at the interfaces where mode conversion occurs. The technique is not limited to the hard surfaces of the Arctic and should work in any well, either land or marine, that penetrates shallow interfaces where mode conversion can occur.

Hydrocarbon Type Identification With MWD Neutron Porosity Logging: A Case Study

Summary Measurement-while-drilling (MWD) information accurately defined gas, oil, and water in an offshore field. Basic MWD and wireline formation evaluation data compare favorably. A cost saving of $130, 000 was realized when MWD information was used instead of wireline data on one well. In the future, MWD logs may serve as the primary evaluation data on routine development wells in similar fields.

Evaluating Gas Content of Black Warrior Basin Coalbeds From Wireline Log Data

Summary Coalbeds have long been known to contain natural gas in varying amounts. To the mining industry, this is basically a hazard to be controlled and avoided where possible. To the petroleum industry, it is an exploitable resource that holds significant economic potential because of shallow drilling and the promise of long well life. The variability of coal as a gas reservoir raises the need for oil-and gas-well explorers to develop the capability of evaluating coalbed gas content to identify and produce coal gas plays. Current petrophysical models for gas reservoir analysis in traditional clastic or carbonate environments are notably inadequate for evaluation of gas content in coalbeds. However, numerous physical models exist for coals throughout the country, primarily from the efforts of the mining industry. A theoretical model was chosen and used to establish a method for evaluating gas content of coalbeds in the Black Warrior basin of Alabama. Core data in the form of proximate analysis, ultimate analysis, and gas desorption measurements were used, along with wireline data, to build the models. Results of data analysis in wells with coals ranging from low-volatile bituminous to high-volatile B bituminous are compared with core gas desorption measurements to demonstrate the accuracy of the process. The thin coals in the Black Warrior basin require high-resolution logging (especially neutron and density tools) to obtain acceptable results. Wireline computations on a prospective well can be obtained much sooner than core desorption measurements and can provide analyses in zones where samples were not recovered. Implementation of these techniques in conjunction with core measurements can help significantly in determining the economic viability of coalbed-methane prospects.