Conventional Log Analysis Research Articles

Prediction of multiscale laminae structure and reservoir quality in fine-grained sedimentary rocks: The Permian Lucaogou Formation in Jimusar Sag, Junggar Basin

Fine-grained sedimentary rocks have become a research focus as important reservoirs and source rocks for tight and shale oil and gas. Laminae development determines the accumulation and production of tight and shale oil and gas in fine-grained rocks. However, due to the resolution limit of conventional logs, it is challenging to recognize the features of centimeter-scale laminae. To close this gap, complementary studies, including core observation, thin section, X-ray diffraction (XRD), conventional log analysis, and slabs of image logs, were conducted to unravel the centimeter-scale laminae. The laminae recognition models were built using well logs. The fine-grained rocks can be divided into laminated rocks (lamina thickness of <0.01 m), layered rocks (0.01–0.1 m), and massive rocks (no layer or layer spacing of >0.1 m) according to the laminae scale from core observations. According to the mineral superposition assemblages from thin-section observations, the laminated rocks can be further divided into binary, ternary, and multiple structures. The typical mineral components, slabs, and T 2 spectrum distributions of various lamina types are unraveled. The core can identify the centimeter–millimeter-scale laminae, and the thin section can identify the millimeter–micrometer-scale laminae. Furthermore, they can detect mineral types and their superposition sequence. Conventional logs can identify the meter-scale layers, whereas image logs and related slabs can identify the laminae variations at millimeter–centimeter scales. Therefore, the slab of image logs combined with thin sections can identify laminae assemblage characteristics, including the thickness and vertical assemblage. The identification and classification of lamina structure of various scales on a single well can be predicted using conventional logs, image logs, and slabs combined with thin sections. The layered rocks have better reservoir quality and oil-bearing potential than the massive and laminated rocks. The laminated rocks’ binary lamina is better than the ternary and multiple layers due to the high content of felsic minerals. The abovementioned results build the prediction model for multiscale laminae structure using well logs, helping sweet spots prediction in the Permian Lucaogou Formation in the Jimusar Sag and fine-grained sedimentary rocks worldwide.

The Importance Of Litho-Facies Distinction In Determining The Most Representative Cementation Factors For Well-Log Evaluation : An Old Issue Persistently Neglected

Cementation factor is a parameter always required in any conventional open-hole log analysis leading to determination of water saturation. Considering the central of water saturation in the estimation of hydrocarbon in place and reserves, any error in the use of the parameter may prove fatal. A common practice in the oil industry is that acquisition of laboratory-derived cementation factor has never been given a proper attention. It occurs very often that too few samples – hardly represent the rocks of reservoir of concern – are assigned for laboratory test. The practical use of the parameter in the log analysis also often draw question, in which un-representative cementation factor is arbitrarily used due to lack of the data. The effect of this practice has long been known but is often neglected – with all of its consequences – up to present day. This study tries to revive the awareness through presenting a fact that cementation factor may vary due to differences in litho-facies characteristics. Formation resistivity factor data from forty-seven limestone coreplug samples were taken from a West Java (WJ) field. Visual description over the samples has shown that they belong to several litho-facies types. Results of the study have mainly proved that different litho-facies type may have significantly different cementation factors. An averaging effect is also obvious when data from all samples are processed collectively. The effect of improper use of cementation factor is shown through the application of three water saturation models through which erroneous water saturation estimates are produced. The finding of the study is again hoped to reinforce the awareness of the use of proper and representative cementation factor

Use of Inline Spinner for Determination of Zonal Flow Rates in Vertical and Moderately Deviated Wells

Summary Accurate zonal flow rate determination is necessary for better reservoir behavior understanding and for making important decisions that can improve well productivity. Knowledge of the capabilities of different reservoir zones in the same well also has significant importance in reservoir performance monitoring and selection of perforation intervals in development wells. Conventional production log analysis techniques can usually yield good results only if the fullbore spinner readings are reliable. However, the fullbore spinner measurement may not be available in some wells. Examples include cases in which the fullbore spinner cannot access the well due to mechanical obstruction, or when the casing is not clean enough, causing potential plugging of fullbore spinner blades. In these situations, the fullbore flow-rate readings may not be available or at least unclear or confusing, which may lead to incorrect decisions. In many of these situations, inline spinner (ILS) data may be readily available. The ILS is often used for qualitative interpretation (i.e., determining which zones are producing), but there is not a specific method to use the ILS for a quantitative solution in the absence of surface measurements of rates. In this paper, we introduce a new method to calculate the volumetric zonal flow rate using ILS data with high accuracy. Approximately 40 oil wells are used to develop an empirical correlation to compute zonal flow rates from ILS data in casing strings. The new method was used to quantitatively interpret eight oil wells for validation. In these wells, fullbore and ILS data were significantly different. The new method for interpretation of ILS data provided results consistent with surface production tests and led to decisions that contributed to increasing production rates.

Technology Focus: Mature Fields and Well Revitalization (January 2019)

Technology Focus Mature brownfields contribute significantly to global oil production. A study of the papers presented during the past year at various SPE conferences reveals a continuation of the trend to put in massive effort to minimize decline from mature brownfields. This has been attempted through several means, such as improving well integrity and judicious well interventions to restart production from idle wells. One paper discusses a conceptual platform where all stakeholders (operator and service providers) can share and formulate a win/win strategy wherein operational efficiency and success rate of an activity are the main drives. As an offshoot of such well-intervention activities, low-resistivity pay zones, either shallower or deeper with respect to the main pay and hitherto considered unattractive, have been identified and contribute significantly in sustaining production decline. There is an all-around emphasis on characterizing highly compartmentalized and difficult reservoirs that have thin reservoir sands defying well-to-well correlations because of a lack of marker shales. In some cases, the presence of conductive minerals such as pyrites or siderites further masks the presence of hydrocarbons in conventional log analysis. In addition to efforts on improved reservoir characterization, optimizing ongoing waterfloods is an area where focused efforts are yielding rich dividends. These involve locating the bypassed oil and addressing unswept areas through reservoir surveillance and modeling. Some operators also have focused on innovative enhanced-oil-recovery techniques in mature brownfields to enhance production. Recommended additional reading at OnePetro: www.onepetro.org. SPE 186362 Extending Life of Liquid-Loaded Gas Wells Using Velocity-String Application: Case Study and Candidate Selection by Satria Andrianata, VICO Indonesia, et al. SPE 188443 Novel Reservoir-Modeling and Experimental-Design Approach To Tackle the Challenge of Modeling Highly Compartmentalized Reservoirs Under Large Uncertainties in a Mature Offshore Field, Malaysia by A. Sulaksana, Sabah Shell, et al. SPE 188770 Fluid-Front Monitoring Using Smart and Safe Pulsed-Neutron Technology on Slickline by Rahul Grover, Schlumberger, et al.

Well log data analysis for lithology and fluid identification in Krishna-Godavari Basin, India

Well log analysis provides the information on petrophysical properties of reservoir rock and its fluid content. The present study depicts interpretation of well log responses such as gamma ray, resistivity, density and neutron logs from six wells, namely W-1, W-2, W-9, W-12, W-13 and W-14 under the study area of Krishna-Godavari (K-G) basin. The logs have been used primarily for identification of lithology and hydrocarbon-bearing zones. The gamma ray log trend indicates deposition of cleaning upward sediment. Coarsening upward, clayey-silty-sandy bodies have been evidenced from the gamma ray log. Gas-bearing zones are characterised by low gamma ray, high deep resistivity and crossover between neutron and density logs. Total 14 numbers of hydrocarbon-bearing zones are identified from wells W-9, W-12, W-13 and W-14 using conventional log analysis. Crossplotting techniques are adopted for identification of lithology and fluid type using log responses. Crossplots, namely P-impedance vs. S-impedance, P-impedance vs. ratio of P-wave and S-wave velocities (Vp/Vs) and lambda-mu-rho (LMR), have been analysed to discriminate between lithology and fluid types. Vp/Vs vs. P-impedance crossplot is able to detect gas sand, brine sand and shale whereas P-impedance vs. S-impedance crossplot detects shale and sand trends only. LMR technique, i.e. λρ vs. μρ crossplot is able to discriminate gas sand, brine sand, carbonate and shale. The LMR crossplot improves the detectability and sensitivity of fluid types and carbonate lithology over other crossplotting techniques. Petrophysical parameters like volume of shale, effective porosity and water saturation in the hydrocarbon-bearing zones in these wells range from 5 to 37%, from 11 to 36 and from 10 to 50% respectively. The estimated petrophysical parameters and lithology are validated with limited core samples and cutting samples from five wells under the study area.

Petroleum geology of the Cygnus gas field, UK North Sea: from discovery to development

Abstract The Cygnus Field, operated by ENGIE E&amp;P UK Limited, is located in UK Southern North Sea blocks 44/11 and 44/12. The reservoir comprises sandstones of the Permian Leman Sandstone Formation and Carboniferous Ketch Formation. Cygnus was first drilled in 1988 by well 44/12-1, which encountered gas shows in sandstones in the Leman Sandstone Formation whilst targeting a Carboniferous objective. The initial evaluation indicated the presence of poor-quality reservoir with conventional log analysis indicating high water saturations. Further appraisal activity ceased until 2002 when a group led by ENGIE E&amp;P UK Limited were awarded the licence in the 20th round having recognized the missed pay potential. Through appraisal drilling, a second reservoir (the Carboniferous Ketch Formation) was discovered and the Leman Sandstone Formation was proven to be capable of achieving stabilized flow rates greater than 30 MMscf/d. The Cygnus discovery now proves that a northern-sourced Leman Sandstone Formation play fairway exists, establishing an extension of the Rotliegend play to the northern feather edge of the Southern Permian Basin. The Cygnus Field's estimated ultimate recoverable volume is forecast to be 760 Bscf, making it the largest field discovered in the UK Southern North Sea in the last 30 years.

Calculation of water saturation in low resistivity gas reservoirs and pay-zones of the Cretaceous Grudja Formation, onshore Mozambique basin

The water saturation of a hydrocarbon bearing formation is usually calculated via the conductivity of the formation water, as defined by Archie, 1942. However, in some formations such conventionally calculated water saturation contradicts values calculated from the Nuclear Magnetic Resonance (NMR) tool and from the Drill Stem Test (DST). Here we discuss such a case of low resistivity pay zones in the J- and K-Reservoirs, of the Lower Grudja Formation of Maastrichtian age, onshore Mozambique basin, in which conventional log analysis contradicts water saturation calculated from the NMR and by the Drill Stem Test.For both, the J-Reservoir and K-Reservoir, the water saturation (Sw) was calculated using the Archie equation and the Simandoux equation, that accounts for clay bound water but not for silt, and the results were compared to NMR-calculated water saturation. A new algorithm that improves the accuracy of water saturation calculation was introduced. This new algorithm takes into account the clay- and silt-bound water within the overall reservoir resistivity. It is demonstrated that the clay- and silt-bound water must be included in water saturation calculations, where the formations are rich in silt and clay. The Simandoux equation and the new algorithm yield significant improvement in water saturation results for the J- and K-Reservoirs, when compared to water saturation calculated using the Archie's equation.

Identification of stratigraphic formation interfaces using wavelet and Fourier transforms

The purpose of this study was to identify the formation interfaces from geophysical well log data using the wavelet transform, and a combination of the wavelet transform and the Fourier transform methods. In the wavelet transform method, the identification of formation interfaces is based on the wavelet coefficients from the wavelet transform of spontaneous potential (SP) log and gamma ray (GR) log data. In the combination of the wavelet transform and the Fourier transform methods, the wavelet transform, spectrum analysis, and logarithmic transform of well logs were applied to the SP and GR log data successively to obtain clear signals for identifying the stratigraphic formation interface. In this study, a set of ideal log data was first created and analyzed to test the validity of the developed procedures. In analyzing the SP and GR logs from a field, both the wavelet transform method and conventional well log analysis showed similar results. The results from a combination of the wavelet transform and the Fourier transform methods, however, were better than those from the wavelet transform method and the conventional well log analysis.

Permeability Estimation From Well Log Responses

Abstract Permeability is one of the most important characteristics of hydrocarbon bearing formations. Formation permeability is often measured in the laboratory from reservoir core samples or evaluated from well test data. However, core analysis and well test data are usually only available from a few wells in a field. On the other hand, almost all wells are logged. This paper presents a non-parametric model to predict reservoir permeability from conventional well log data using an artificial neural network (ANN). The ANN technique is demonstrated by applying it to one of Saudi Arabia's oil fields. The field is the largest offshore oil field in the world and was deposited in a fluvial dominated deltaic environment. The use of conventional regression methods to predict permeability in this case was not successful. The ANN permeability prediction model was developed using some of the core permeability and well log data from three early development wells. The ANN model was built and trained from the well log data and their corresponding core measurements by using a back propagation neural network (BPNN). The resulting model was blind tested using data which was taken from the modelling process. The results of this study show that the ANN model permeability predictions are consistent with actual core data. It could be concluded that the ANN model is a powerful tool for permeability prediction from well log data. Introduction Many oil reservoirs have heterogeneity in rock properties. Understanding the form and spatial distribution of these heterogeneities is fundamental to the successful exploitation of these reservoirs. Permeability is one of the fundamental rock properties, which reflects the rock's ability to transmit fluids when subjected to pressure gradients. While this property is very important in reservoir engineering, there is no specific geophysical well log for permeability, and its determination from conventional log analysis is often unsatisfactory(1). In general, porosity and permeability are independent properties of a reservoir. However, permeability is low if porosity is disconnected, whereas permeability is high when porosity is interconnected and effective. Despite this observation, theoretical relationships between permeability and porosity have been formulated, such as the Kozeny-Carmen theory. The Kozeny-Carmen theory relates permeability to porosity and specific surface area of a porous rock which is treated as an idealized bundle of capillary tubes. This theory, however, ignores the influence of conical flow in the constrictions and expansions of the flow channels and treats the highly complex porous medium in a very simple manner. Empirical relationships based on the Kozeny-Carmen theory have also been developed that relate permeability to other logs and/or log-derived parameters such as resistivity and irreducible water saturation(2). These relationships are applied only to the region above the transition zone or to the transition zone itself. Since core permeability data are available for most exploration and development wells, statistical methods have become a more versatile alternative in solving the problem of determining reservoir permeability. Regression is widely used as a statistical method to search for relationships between core permeability and well log parameters(3, 4).

Pore microgeometry analysis in low-resistivity sandstone reservoirs : Cerepi, A. et al. Journal of Petroleum Science and Engineering, 2002, 35, (3–4), 205–232

The water saturation of a hydrocarbon bearing formation is usually calculated via the conductivity of the formation water, as defined by Archie, 1942. However, in some formations such conventionally calculated water saturation contradicts values calculated from the Nuclear Magnetic Resonance (NMR) tool and from the Drill Stem Test (DST). Here we discuss such a case of low resistivity pay zones in the J- and K-Reservoirs, of the Lower Grudja Formation of Maastrichtian age, onshore Mozambique basin, in which conventional log analysis contradicts water saturation calculated from the NMR and by the Drill Stem Test.For both, the J-Reservoir and K-Reservoir, the water saturation (Sw) was calculated using the Archie equation and the Simandoux equation, that accounts for clay bound water but not for silt, and the results were compared to NMR-calculated water saturation. A new algorithm that improves the accuracy of water saturation calculation was introduced. This new algorithm takes into account the clay- and silt-bound water within the overall reservoir resistivity. It is demonstrated that the clay- and silt-bound water must be included in water saturation calculations, where the formations are rich in silt and clay. The Simandoux equation and the new algorithm yield significant improvement in water saturation results for the J- and K-Reservoirs, when compared to water saturation calculated using the Archie's equation.

A North Louisiana Gas-Prone Hosston Slope-Basin Sand Trend

ABSTRACT Regional palinspastic reconstructions of north Louisiana's down-dip Hosston strata offer a basis for predicting the most likely area that might have contained deep-water sand deposition at the beginning of early Cretaceous time. Since the area's deep well control to the base of the Hosston is very limited, future regional 3-D seismic surveys will remain the preferred way of predicting individual sand trends. However, an in-depth integrated modeling and simulation analysis of the regional stratigraphic, structural, and thermal history provides one method of defining the main potential prospective trend. Furthermore, this type of analysis, in conjunction with conventional petrophysical log analysis, provides a method for (1) determining the location of specific trend segments that appear more sandprone, and (2) defining the confining window of thermal maturation where hydrocarbon potential still may remain. A predicted trend area for deep-water sand development, compatible with the present hydrocarbon maturation window, covers a gross area with dimensions of 20-40 miles (32-64 km) in width and 110-140 miles (177-225 km) in length. The area extends eastward across the State from the south flank of the Sabine uplift. Up-dip, the area is situated mainly within the southern confines of the North Louisiana Salt Dome Basin and extends down-dip to the northern edge of the South Louisiana Salt Dome Basin. On the north, its limit is expected to be governed by individual sand bodies encased and terminated in fore-shelf claystones. The trend's southern limit can be defined by its containment within thermally over-matured strata which create an economic drilling barrier.

Forward modelling of the physical properties of oceanic sediments: constraints from core and logs, with palaeoclimatic implications

Abstract A new methodological approach based on the analysis of core data, logs and high-resolution electrical images of borehole surfaces (FMS) is developed in order to improve the study of oceanic sediments from physical properties. This approach is tested on data obtained in the context of the Ocean Drilling Program (Japan Sea, Leg 128, Hole 798B). The downhole measurements and FMS images exhibit a cyclic pattern reflecting variations in oceanic surface productivity combined with continental aeolian supply due to palaeoclimatic changes. On the basis of m-scale physical measurements, cm-scale FMS images and measurements on core, the objective is to deconvolve the variations in sedimentary supply of oceanic and continental components through time and to compute the intrinsic formation factor versus depth. The latter topic is approached in two ways: first by conventional log analysis, then with a new iterative forward modelling method. In the second case, the low frequency electrical resistivity log (SFL) is modelled using a numerical modelling code (Resmod2D © ) in order to obtain an accurate formation electrical resistivity model (Rt), where individual beds are derived from FMS images. An analytical routine is also used to model the natural gamma-ray measurement (CGR). While the conventional log analysis allows deconvolution of the sedimentary supplies, the forward modelling leads to a greater resolution and accuracy in more precise sediment characterization, such as that obtained from the derivation of the formation factor.

Petrophysical estimation from downhole Mineralogy logs

Abstract A number of physical and chemical properties of rocks, many of which are important in petrophysics are simple, usually linear functions, of a rock’s mineralogy. Examples include matrix density, porosity, magnetic susceptibility and cation exchange capacity. Mineralogy logs can be obtained directly from geochemical logs through an inversion process and, in turn, estimates of petrophysical properties such as those noted above can be obtained. The accuracy of such estimates is directly dependent on the quality of both the inversion and the geochemical measurements. Examples from producing oil fields and from deep-sea environments are used to show that accurate estimates of derived parameters can be obtained provided that appropriate inversion procedures are adopted, and that these estimates are generally better than those obtained by conventional log analysis. Logs of some parameters, such as cation exchange capacity, cannot be obtained except through the mineral inversion.

An Improvement in Lithology Interpretation from Well Logs in the Patchawarra Formation, Toolachee Field, Cooper Basin, South Australia

Conventional lithology interpretation from well log data becomes unreliable when the target bed is thinner than the vertical resolution limit of the logging tools. The thin bed log analysis method of Bateman (1990), using the concept of binary lithology and a filtering technique applied to conventional logging suites, is able to detect beds as thin as 15 cm. This paper will focus on the use of the Bateman method to improve log-derived lithology estimates in the Permian Patchawarra Formation sandstone gas reservoirs in the Toolachee Field of the southern Cooper Basin in South Australia. In three representative wells, conventional log analysis overlooks most of the thin sandstone beds and underestimates the gross sandstone by up to 36% when compared with core data. In contrast, the thin bed algorithm identifies the thin sandstone beds and gives a gross sandstone thickness which agrees with the core value to within about 5%. It therefore provides a more correct picture of reservoir rock distribution, and reveals more potential pay than conventional log analysis. The method also makes core to log depth matching easier and more accurate. Log character and flow test results imply the presence of relatively permeable gas-bearing zones within some of the thin sandstone beds, suggesting that overlooking thin bed reservoirs may significantly lower reserve estimates. Since the method does not require the use of any high resolution logging device, it is possible to re-evaluate old log data for which conventional log analysis is subject to such under-estimation.

Reservoir Characteristics And Petroleum Potential of the Bakken Formation, Southwestern Manitoba

Abstract The Bakken Formation lies between the Upper Devonian Three Forks (Lyleton) Formation and the Mississippian Lodgepole Formation. The productive Middle Member of the Bakken Formation is a very fine- to fine-grained, argillaceous, dolomitic sandstone to siltstone. This paper outlines the geological setting in southwestern Manitoba and presents the general stratigraphy and lithology of the Bakken Formation. Conventional log analysis techniques result in erroneous calculations of porosity and water saturation for the litho-logically complex Middle Member. This paper illustrates the log analysis techniques developed to determine accurate porosity and water saturation for the Bakken Middle Member. Reservoir properties and production performance under both primary and secondary recovery for Bakken pools in Manitoba is also presented. Low drilling and completion costs; the province's drilling incentive program; high quality oil (over 40 ° API); and, original oil-in-place per pool of 500 × 103m3, make the Bakken an attractive exploration target in Manitoba. Bakken exploration and development prospects are discussed, including a brief overview of Bakken source rock and migration pathways and sample development drilling economics. Introduction The Bakken discovery well in Manitoba, 13-21-10-29(WPM) was drilled in the Daly Field in 1985. Production from the Bakken Formation in Manitoba is presently restricted to the Daly field (Figure 1), where it produces from the Middle Member. At year end 1992, there were 38 active Bakken producers in five pools in the Daly Field. Total oil production from the Bakken in Mamtoba in 1992 was 23.6 x. 103m3. As of December 31, 1992 cumulative Bakken oil production was 127.9 × 103m3 and remaining established Bakken reserves totalled 97.4 × 103m3. FIGURE 1: Manitoba oil fields and producing areas. (Available in full paper) Geological Setting The Williston Basin occupies portions of North Dakota, South Dakota, Montana, Saskatchewan and Manitoba (Figure 2). The productive areas of southwestern Manitoba are located on the northeastern flank of the Williston Basin. Paleozoic, Mesozoic and Cenozoic rocks form a basin ward-thickening wedge of sedimentary strata that reaches a thickness of 2,300 m in the extreme southwest corner of the province. The Mississippian stratigraphy in the Manitoba portion of the Williston Basin is shown in Table l. In southwestern Manitoba, Mississippian strata, divided into four formations, from the uppermost part of the Paleozoic sequence. These formations, in ascending order are: Bakken Formation, Lodgepole, Mission Canyon and Charles formations of the Madison Group. Approximately 70% of Manitoba's current oil production is from the Bakken, Lodgepole and Mission Canyon formations. The geological discussion in this paper focuses exclusively on the stratigraphy and lithology of the Bakken Formation. Stratigraphy The Bakken Formation is a thin, clastic unit that straddles the Devonian-Mississippian boundary. In southwestern Manitoba, the Bakken Formation uncomfortably overlies the Upper Devonian Three Forks (Lyleton) Formation and underlies the Mississippian Lodgepole Formation. The Bakken Formation is divided into three informal units: the Lower Member, Middle Member and Upper Member (Table 1). The three members exhibit an on-lapping relationship, each successively younger member extensively overlapping the older member(1). The Upper and Middle Members are present throughout southwestern Manitoba.

THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA

The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.

Single Well Tracer Testing For Connate Water Saturation At Utikuma Lake: Field Application

Abstract Three Single Well Tracer (SWT) tests for Connate Water Saturation (Swc) have been successfully conducted in the Keg River Sand at the major Utikuma Lake oilfield, leading to significant reductions in estimated Swc and increases in reserves. Resistivity logs and conventional core analysis yield erroneously high Swc in the Utikuma Keg River Sand due to thinly interbedded sands and shales, and severe wettability alteration in restored core. SWT testing allows in situ measurement of Swc in productive sand intervals only, investigating saturations within a 5 m radius of investigation. The Utikuma tests represent the latest 3 of 10 tests conducted worldwide. They are the first SWT tests for Swc to use a novel downhole equipment configuration to avoid plugging by waxy crude. They also introduced the use of ethyl formate as the primary tracer for accurate measurement of Swc in 5% to 15% range. SWT results are supported by NGT/GST logs run during the programs, and the first public verification by oil base Core. Introduction Utikuma Lake Field is located north of the town of Slave Lake, Alberta, between the Nipisi and Red Earth fields (Fig. 1). Field characteristics are summarized in Table 1. Utikuma produces 1500 m3/d of light, sweet oil under primary water drive from 180 wells completed in the Keg River Sandstone. The Keg River sands are deposited in Utikuma as numerous separate pools, laid over geological unconformities in the Precambrian granite. Average porosities and permeabilities for the Keg River sands are 20% and 1000 mD. Average net pay is 3 m. Utikuma Keg River oil is paraffinic with low asphaltene content. Oil properties are listed in Table 2. Formation water is highly saline, with 275 000 mg/l total dissolved solids, as indicated in the water analysis data presented in Table 3. Connate Water Saturation Determination at Utikuma Connate Water Saturations (Swc's) of 29% based on early log and special core data have been recognized for Utikuma Keg River pools since discovery. Recognized inaccuracies in open hole log data and concerns over reliability of early core flood data led to further investigation of Swc. Accurate Swc data was required to calculate reserves and determine a development strategy for the field. Increased reserves and production gains by increasing reserves-based Maximum Rate Limitation (MRL) provided economic incentive to aggressively pursue the program of Swc determination through Single Well Tracer (SWT) testing described in this paper. Swc from Resistivity Logs Swc determination from conventional resistivity logs is hampered in the Utikuma Keg River Sandstone by thin interbedding of sands and shales, and bed thicknesses less than the 2.4 m vertical resolution of resistivity tools. Radioactive feldspars affect Gamma Ray response, preventing shaly sand analysis. Swc's of 30% to 60% are typically obtained from conventional and shaly sand log analysis in the Utikuma Keg River Sandstone. Swc from Core Utikuma Keg River sand is a feldspar-rich quartzose as indicated in the X-ray Diffraction analysis presented in Table 4.

FRESHWATER INFLUX IN THE GIPPSLAND BASIN: IMPACT ON FORMATION EVALUATION, HYDROCARBON VOLUMES, AND HYDROCARBON MIGRATION

The recognition and quantitative evaluation of hydrocarbon zones in the Gippsland Basin is complicated by the presence of a freshwater aquifer system. This aquifer system has been verified and documented using data obtained from wireline logs. The presence of freshwater aquifers below the hydrocarbon sands leads to (i) difficulty in distinguishing the hydrocarbon zones from the water sands using well logs, and (ii) difficulty in determining accurate water saturation values used in estimating hydrocarbon volumes.Water saturations calculated from logs require the input of a formation water salinity. In conventional log analysis the formation water salinity in the hydrocarbon zones is assumed to be the same as that of the underlying water sands. In reservoirs in the Gippsland Basin underlain by freshwater aquifers, calculated water saturations using the salinities of the water sands are inconsistent with capillary pressure, Repeat Formation Tester (RFT*-Schlumberger), and production test data. All available evidence suggests that the formation water salinities within the hydrocarbon zones are significantly greater than in the freshwater aquifers. The water saturations derived using the higher salinity values lead to the calculation of greater hydrocarbon volumes.The occurrence of saline formation waters within the hydrocarbon zones leads to the interpretation that significant volumes of hydrocarbon were emplaced prior to the formation of the freshwater aquifer system. Subsequent freshwater influx did not flush the emplaced hydrocarbons.

A New Approach To Fracturing The Milk River Formation In Southeastern Alberta

Abstract The shallow Milk River gas sands of southeastern Alberta contain significant gas reserves. Recent improvements in production logging techniques and greater reservoir and completion knowledge of the Milk River zone indicated that current fracturing techniques were less than adequate to develop the potential of this zone. A series of wells were completed using conventional Milk River fracture treatments and then logged to determine the effectiveness of the fracture treatment on the Milk River zone. The results indicated that only one or two sets of perforations were being stimulated. On the basis of the above information, a stage fracturing technique was designe1t in which the Milk River zone would be fractured in two separate treatments. The fracture treatments were also redesigned to complement the new fracturing technique. Two separate Medicine Hat/Milk River shallow gas projects were chosen to evaluate the effectiveness of the stage fracturing concept and the redesigned fracture treatments. The initial after fracture results indicated a 91% and 130% improvement in productivity from the Milk River zone, for the respective projects. The results obtained to date validate the concept of stage fracturing the Milk River zone. The initial average increased gas production from the Milk River zone of 6 100 m3/d (STD) and its related $20 000 cost has a payout period of approximately 43 days per well. Long term production tests are being undertaken to determine if there is a sustained level of increased production between the wells recently completed and wells previously completed using the old fracturing techniques. Introduction Throughout the past ten years there has been considerable ctivity in the southeastern portion of Alberta, one of the main zones of interest being the gas bearing Milk River formation. Figure I indicates the location of the Milk River formation in Alberta. The Milk River formation is found at relatively shallow depths and hence is often referred to as shallow gas. The Milk River formation has a gross thickness of approximately 110m. The formation is an extremely heterogeneous mixture of coarse grained siltstone varying to fine sandstone irregularly distributed through a dark to medium, grey, soft, silty shale. The siltstones have a high clay content, the predominant constituents being the Kaolinite and Illite clays. The clays often account for as much as 10% of the bulk volume. The average permeability values of the Milk River formation are less than 0.1 md. Hydraulic fracturing is required to increase productivity due to the low permeability thickness of the reservoir and the low reservoir pressure. Identification of potential zones on logs has been hampered by the fact that connate water in the Milk River is fresh and prevents the differentiation of gas from water using a standard resistivity log. The producible sand lenses in this reservoir have been difficult to detect using conventional log analysis due to the shaliness of the reservoir. In the last ten years, better logging tools such as the Dual Spacing Thermal Neutron Decay Time Log and the Neutron Lifetime Log, both previously Described(l) (2), have been developed to better define potential zones.

Use of Microresistivity From the Dipmeter To Improve Formation Evaluation in Thin Sands, Northeast Kalimantan, Indonesia

Summary Estimation of reserves in lenticular reservoirs consisting of many thin-bedded sand/shale sequences is complicated by an overly pessimistic evaluation of sand count and hydrocarbon in place when conventional log interpretation techniques are used. It is probable that thin clean sand lenses have connected permeability. Their contribution to production should be considered in the estimation of reserves. An approach has been devised to improve the evaluation of thin clean sands by introducing accurate bed boundaries between sand and shale laminae as identified clearly on the dipmeter microresistivity curve processing presentation (GEODIP). Dipmeter data are integrated presentation (GEODIP). Dipmeter data are integrated into conventional computer log analyses to yield more realistic estimates of porosity and hydrocarbon saturation throughout the reservoir. The method and the results attained to date are described. Introduction The subject of this paper is a producing field in the Tarakan basin of northeast Kalimantan, Indonesia. It was discovered in late 1975 and has produced since 1977. Reservoirs are upper-middle Miocene sandstones that were deposited in a lower delta plain to front tidaldominated environment. The thin (less than 5 ft [1.5 m]) and interbedded nature of the oil reservoirs throughout this field has led to inaccurate oil in place (OIP) estimates on the basis of conventional log analyses. This paper demonstrates (1) how the thin sands were overlooked in the calculation of reserves in the initial log analysis, (2) the means by which the correct interpretation of this reservoir has been accomplished on 12 producing wells in this field, and (3) how the newly producing wells in this field, and (3) how the newly developed quantitative method of evaluating these thin reservoirs has been accomplished. The inaccuracy of conventional log analysis and its effect on reserve calculations did not appear significant until a later date when cumulative production data were interpreted. These production data, in conjunction with drillstem tests (DST's), which have produced oil from thin sands, have now been evaluated with respect to the log and core data previously gathered. The standard suite of logs was run on each well in this field. However, not until recently did we develop a technique to adapt accurately the log interpretation to evaluate the thin-bedded nature of these reservoirs. This adaptation uses logs and extends normal interpretation with the aid of recently developed computer programs. The interpretation of the reservoir geology has become the most important aspect of the evaluation and analysis of reserves in this producing field. Initial Log Analysis The early logging program included the induction electic log (IES), sonic, formation density log/compensated neutron log (FDC/CNL), MLL/Microlog, and dipmeter (HDT). In later wells, the (induction spherical focused) ISF/sonic replaced the IES and the dual laterolog (DLL) was added also. The oil producing interval is within a gross sand/shale sequence 1,000 to 1,400 ft [305 to 427 m] thick. Initial log analyses indicated relatively clean sands ranging from 5 to 20 ft [1.5 to 6 m] thick. The logs showed the hydrocarbon-bearing sands to have resistivities of more than 10 and commonly to 30 0 in the thicker sands (Fig. 1). Porosities range from 18.5 to 27.7% across the field in the well-developed thicker sands. These sands have produced individually more than 2,000 B/D [318 m 3 /d] on a DST. These clean sands commonly add up to more than 100 ft [30.5 m] of net estimated oil pay in the structurally high wells. (See Fig. 9 for original net pay calculation.) Conventional cores taken over a portion of the reservoir section showed that in addition to major sand bodies there also were sequences that consisted of thinly interbedded clean sand and shale. Early log analyses of these thinly interbedded sequences indicated that throughout the producing section, in addition to the clean sands, there are many other sand intervals that range in their log response from shaly to very shaly. These sands usually exhibit resistivities from 4 to 10 (Fig. 1). Use of standard V-clay (clay volume) corrections of Coriband generally yields average porosities in the range of 5 to 12% in these sands. porosities in the range of 5 to 12% in these sands. JPT p. 1535