Theoretical and Experimental Bases for the Dual-Water Model for Interpretation of Shaly Sands

1984 ◽  
Vol 24 (02) ◽  
pp. 153-168 ◽  
Author(s):  
C. Clavier ◽  
G. Coates ◽  
J. Dumanoir
Keyword(s):  
Volume Fraction ◽  
Water Saturation ◽  
Free Water ◽  
Total Porosity ◽  
Water Model ◽  
Implicit Assumption ◽  
Formation Water ◽  
Formation Factor ◽  
Water Conductivity ◽  
Clayey Sand

Abstract A simple petrophysical model proposed by Waxman and Smits (WS)1 in 1968 and Waxman and Thomas (WT)2 in 1972 accounts for the results of an extensive experimental study on the effects of clays on the resistivity of shaly sands. This model has been well accepted by the industry despite a few inconsistencies with experimental results. It is proposed that these inconsistencies resulted from the unaccounted presence of salt-free water at the clay/water interface. Electrochemistry indicates that this water should exist, but is there enough to influence the results? Both a theoretical study and reinterpretation of Waxman-Smits-Thomas data show that there is. The corresponding new model starts from the Waxman and Smits concept of supplementing the water conductivity with a conductivity from the clay counterions. The crucial step, however, is equating each of these conductivity terms to a particular type of water, each occupying a representative volume of the total porosity. This approach has been named the "dual-water" (DW) model because of these two water types - the conductivity and volume fraction of each being predicted by the model. The DW model has been tested on most of the core data reported in Refs. 1 and 2. The DW concept is also supported by log data3 and has been successfully applied to the interpretation of thousands of wells. However, the scope of this paper remains limited to the theoretical and experimental bases of the DW model. The Petrophysical DW Model The purpose of this model is to account for the resistivity behavior of clayey sands. For petrophysical considerations, a clayey formation is characterized by its total porosity, ft; its formation factor, F0; its water saturation, SwT; its bulk conductivity, Ct; and its concentration per unit PV of clay counterions, Qv. The formation behaves like a clean formation with identical parameters ft, F0, and Swt but containing a water whose conductivity, Cwe, differs from the bulk formation water. Neither the type of clays nor their distribution influences the results. Since the formation obeys Archie's laws,Equation 1 The clayey sand equivalent water conductivity, Cwe, can be considered a mixture of two waters. 1. A clay water surrounds the clay particles but has a conductivity independent of the type and amount of clay. Its conductivity, Ccw, comes exclusively from the clay counterions. The volume fraction of clay water, Vcw, is directly proportional to the counterion concentration, QvEquation 2 where vQ is the amount of clay water associated with 1 unit (meq) of clay counterions. 2. The water further away from the clay is called far water. Its conductivity, Cw, and ionic concentration correspond to the salinity of bulk-formation water. The volume fraction of this water, Vfw, is the balance between the total water content and the clay water.Equation 3 The implicit assumption is that the far water is displaced preferentially by hydrocarbons.

Petrophysical Type Curves for Identifying the Electrical Character of Petroleum Reservoirs

2007 ◽  
Vol 10 (06) ◽  
pp. 711-729 ◽  
Author(s):  
Paul Francis Worthington
Keyword(s):  
Water Saturation ◽  
Early Stage ◽  
Well Logs ◽  
Log Analysis ◽  
Well Log ◽  
Formation Water ◽  
Water Conductivity ◽  
Core Data ◽  
Water Saturated ◽  
Petrophysical Evaluation

Summary A user-friendly type chart has been constructed as an aid to the evaluation of water saturation from well logs. It provides a basis for the inter-reservoir comparison of electrical character in terms of adherence to, or departures from, Archie conditions in the presence of significant shaliness and/or low formation-water salinity. Therefore, it constitutes an analog facility. The deliverables include reservoir classification to guide well-log analysis, a protocol for optimizing the acquisition of special core data in support of log analysis, and reservoir characterization in terms of an (analog) porosity exponent and saturation exponent. The type chart describes a continuum of electrical behavior for both water and hydrocarbon zones. This is important because some reservoir rocks can conform to Archie conditions in the fully water-saturated state, but show pronounced departures from Archie conditions in the partially water-saturated state. In this respect, the chart is an extension of earlier approaches that were restricted to the water zone. This extension is achieved by adopting a generalized geometric factor—the ratio of water conductivity to formation conductivity—regardless of the degree of hydrocarbon saturation. The type chart relates a normalized form of this geometric factor to formation-water conductivity, a "shale" conductivity term, and (irreducible) water saturation. The chart has been validated using core data from comprehensively studied reservoirs. A workflow details the application of the type chart to core and/or log data. The analog role of the chart is illustrated for reservoir units that show different levels of non-Archie effects. The application of the method should take rock types, scale effects, the degree of core sampling, and net reservoir criteria into account. The principal benefit is a reduced uncertainty in the choice of a procedure for the petrophysical evaluation of water saturation, especially at an early stage in the appraisal/development process, when adequate characterizing data may not be available. Introduction One of the ever-present problems in petrophysics is how to carry out a meaningful evaluation of well logs in situations where characterizing information from quality-assured core analysis is either unavailable or is insufficient to satisfactorily support the log interpretation. This problem is especially pertinent at an early stage in the life of a field, when reservoir data are relatively sparse. Data shortfalls could be mitigated if there was a means of identifying petrophysical analogs of reservoir character, so that the broader experience of the hydrocarbon industry could be utilized in constructing reservoir models and thence be brought to bear on current appraisal and development decisions. Here, a principal requirement calls for type charts of petrophysical character, on which data from different reservoirs can be plotted and compared, as a basis for aligning approaches to future data acquisition and interpretation. This need manifests itself strongly in the petrophysical evaluation of water saturation, a process that traditionally uses the electrical properties of a reservoir rock to deliver key building blocks for an integrated reservoir model. The solution to this problem calls for an analog facility through which the electrical character of a subject reservoir can be compared with others that have been more comprehensively studied. In this way, the degree of confidence in log-derived water saturation might be reinforced. At the limit, the log analyst needs a reference basis for recourse to capillary pressure data in cases where the well-log evaluation of water saturation turns out to be prohibitively uncertain.

Formation Evaluation With NMR, Resistivity, and Pressure Data: A Case Study of a Carbonate Oil Field Off shore West Africa

2021 ◽  
Vol 62 (1) ◽  
pp. 73-88
Author(s):  
Ting Li ◽  
◽  
Nicholas Drinkwater ◽  
Karen Whittlesey ◽  
Patrick Condon ◽  
...  
Keyword(s):  
West Africa ◽  
Water Saturation ◽  
Pore Space ◽  
Free Water ◽  
Total Porosity ◽  
Poor Quality ◽  
Oil Field ◽  
Water Volume ◽  
Pressure Gradients ◽  
Irreducible Water Saturation

In this paper, we examine fluids interpretation techniques in a prolific oil field in offshore West Africa. A sourceless logging program, consisting of logging-while-drilling (LWD) nuclear magnetic resonance (NMR), resistivity, and formation tester, was chosen to log the reservoir section in 6.5-in. holes. The purpose of this study is to answer questions related to asset appraisal and development with these limited measurements. Core data available are porosity, permeability, water salinity, Archie m and n, and Dean-Stark Sw. A comparison of the core and NMR log indicates that NMR total porosity is not affected by hydrocarbon in the pore space. We use a statistical method called factor analysis to deconvolve independent fluid modes from the T2 distribution and pick the T2 cutoff. The NMR irreducible water saturation (Swirr) computed with this cutoff agrees with Dean-Stark Sw. Continuous Sw is calculated with Archie’s equation with lab-measured parameters and validated against Dean-Stark Sw above the transition zone. The Timur-Coates model is used to estimate matrix permeability. The first application of this interpretation workflow is to confirm the free-water level (FWL) derived from pressure gradients. We found the Sw profile largely controlled by heterogeneity in rock textures. The presence of both good and poor-quality rocks makes log-based FWL picking difficult. We use Swirr from NMR to indicate rock quality and simplify our final interpretation. The FWL found by sourceless log interpretation is consistent with the initial FWL found by pressure gradients. The second application is perforation design. Zones with good porosity and low mobile water volume are selected for perforation, and a safe distance is maintained from FWL. As a result, all producer wells exhibit zero water cut.

scholarly journals Petrophysical Analysis of an Iraqi Gas Field (Mansuriya Gas Field)

2020 ◽  
Vol 26 (3) ◽  
pp. 100-116
Author(s):  
Hasan Saleh Azeez ◽  
Dr. Abdul Aali Al-Dabaj ◽  
Dr.Samaher Lazim
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Logarithmic Scale ◽  
Formation Factor ◽  
Gas Field ◽  
The Matrix ◽  
Rock Parameters ◽  
Potassium 40

Mansuriya Gas field is an elongated anticlinal structure aligned from NW to SE, about 25 km long and 5-6 km wide. Jeribe formation is considered the main reservoir where it contains condensate fluid and has a uniform thickness of about 60 m. The reservoir is significantly over-pressured, (TPOC, 2014). This research is about well logs analysis, which involves the determination of Archie petrophysical parameters, water saturation, porosity, permeability and lithology. The interpretations and cross plots are done using Interactive Petrophysics (IP) V3.5 software. The rock parameters (a, m and n) values are important in determining the water saturation where (m) can be calculated by plotting the porosity from core and the formation factor from core on logarithmic scale for both and the slope which represent (m) then Pickett plot method is used to determine the other parameters after calculating Rw from water analysis . The Matrix Identification (MID), M-N and Density-Neutron crossplots indicates that the lithology of Jeribe Formation consists of dolomite, limestone with some anhydrite also gas-trend is clear in the Jeribe Formation. The main reservoir, Jeribe Formation carbonate, is subdivided into 8 zones namely  J1 to J8, based mainly on porosity log (RHOB and NPHI) trend, DT trend and saturation trend.  Jeribe formation was considered to be clean in terms of shale content .The higher gamma ray because of the uranium component which is often associated with dolomitisationl and when it is removed and only comprises the thorium and potassium-40 contributions, showed the gamma response to be low compared to the total gamma ray response that also contains the uranium   contribution.While the Jeribe formation is considered to be clean in terms of shale content so the total porosity is equal to the effective porosity.No porosity cut off is found if cutoff permeability 0.01 md is applied while the porosity cut off approximately equal to 0.1 only for unit J6 & J8 if cutoff permeability 0.1 md is applied . It can be concluded that no saturation cutoff for the units of Jeribe formation is found after a cross plot between water saturation and log porosity for the reservoir units of Jeribe formation and applied the calculated cut off porosity. The permeability has been predicted using two methods: FZI and Classical, the two methods yield approximately the same results for all wells.

An effective medium algorithm for calculating water saturations at any salinity or frequency

Geophysics ◽  
2007 ◽  
Vol 72 (2) ◽  
pp. E59-E67 ◽  
Author(s):  
Charles Berg
Keyword(s):  
Water Saturation ◽  
Low Frequency ◽  
Dielectric Constants ◽  
Data Sets ◽  
Formation Water ◽  
Water Conductivity ◽  
Low Frequencies ◽  
Incremental Model ◽  
Geometric Factors ◽  
Coated Sand

An algorithmic approach is used to mix the conductivities and geometric factors of the disperse components (the rock and hydrocarbon particles) with the host conductivity (formation water). The theoretical basis for the algorithm is the Hanai-Bruggeman (HB) equation, which itself incorporates only one disperse component. The new approach, the incremental model, accommodates geometric factors such as sand and shale porosity exponents, saturation exponent, and also accommodates the associated grain conductivities. Its advantage over previous methods is that it works at any water salinity or tool frequency while allowing saturation and porosity exponents to have values other than 1.5. The algorithm is general and is written to accommodate simultaneous mixing of up to three disperse components and the formation water, but it can be extended to accommodate any number of disperse components. In its application to shaley sands, hydrocarbon and sand elements are set to zero conductivity at low frequency, but they can be nonzero for calculating saturations at higher frequencies. The reason for this is that hydrocarbon and sand conductivities are real and very close to zero at low frequencies, but at high frequencies the dielectric constants become significant, making the complex conductivities nonzero. The incremental model compared well with the Waxman-Smits model on multiple water-conductivity saturation data from two published experimental data sets. The model is adaptable to other rock conductivity problems such as vuggy porosity, vuggy water saturation, and clay-coated sand grains. The potential exists for the algorithm to be part of a comprehensive computer program for calculating rock conductivities and saturations using many different combinations of rock fabrics and compositions.

scholarly journals Petrophysical interpretation in shaly sand formation of a gas field in Tanzania

2019 ◽  
Vol 10 (3) ◽  
pp. 1201-1213
Author(s):  
Oras Joseph Mkinga ◽  
Erik Skogen ◽  
Jon Kleppe
Keyword(s):  
Volume Fraction ◽  
Water Saturation ◽  
Total Porosity ◽  
Published Data ◽  
Petrophysical Properties ◽  
Production Forecast ◽  
Sand Fraction ◽  
Gas Field ◽  
Shale Volume ◽  
Shaly Sand

AbstractAn onshore gas field (hereafter called the R field—real name not revealed) is in the southeast coast of Tanzania which includes a Tertiary aged shaly sand formation (sand–shale sequences). The formation was penetrated by an exploration well R–X wherein no core was acquired, and there is no layer-wise published data of the petrophysical properties of the R field in the existing literature, which are essential to reserves estimation and production forecast. In this paper, the layer-wise interpretation of petrophysical properties was undertaken by using wireline logs to obtain parameters to build a reservoir simulation model. The properties extracted include shale volume, total and effective porosities, sand fractions and sand porosity, and water saturation. Shale volume was computed using Clavier equation from gamma ray. Density method was used to calculate total and effective porosities. Thomas–Stieber method was used to determine sand porosity and sand fraction, and water saturation was computed using Poupon–Leveaux model. The statistics of the parameters extracted are presented, where shale volume obtained that varies with zones is between 6 and 54% volume fraction, with both shale laminations and dispersed shale were identified. Total porosity obtained is in a range from 12 to 22%. Sand porosity varies between 15 and 25%, and sand fraction varies between 33 and 93% height fraction. Average water saturation obtained is between 32 and 49% volume fraction.

Petrographic and Petrophysical Characteristics of the Upper Devonian Three Forks Formation, Southern Nesson Anticline, North Dakota

2017 ◽  
Vol 54 (3) ◽  
pp. 181-201
Author(s):  
Rebecca Johnson ◽  
Mark Longman ◽  
Brian Ruskin
Keyword(s):  
Relaxation Time ◽  
Pore Size ◽  
Water Saturation ◽  
Average Pore Size ◽  
Total Porosity ◽  
Average Pore ◽  
Pore Sizes ◽  
Three Forks Formation ◽  
Three Forks ◽  
Intercrystalline Pores

The Three Forks Formation, which is about 230 ft thick along the southern Nesson Anticline (McKenzie County, ND), has four “benches” with distinct petrographic and petrophysical characteristics that impact reservoir quality. These relatively clean benches are separated by slightly more illitic (higher gamma-ray) intervals that range in thickness from 10 to 20 ft. Here we compare pore sizes observed in scanning electron microscope (SEM) images of the benches to the total porosity calculated from binned precession decay times from a suite of 13 nuclear magnetic resonance (NMR) logs in the study area as well as the logarithmic mean of the relaxation decay time (T2 Log Mean) from these NMR logs. The results show that the NMR log is a valid tool for quantifying pore sizes and pore size distributions in the Three Forks Formation and that the T2 Log Mean can be correlated to a range of pore sizes within each bench of the Three Forks Formation. The first (shallowest) bench of the Three Forks is about 35 ft thick and consists of tan to green silty and shaly laminated dolomite mudstones. It has good reservoir characteristics in part because it was affected by organic acids and received the highest oil charge from the overlying lower Bakken black shale source rocks. The 13 NMR logs from the study area show that it has an average of 7.5% total porosity (compared to 8% measured core porosity), and ranges from 5% to 10%. SEM study shows that both intercrystalline pores and secondary moldic pores formed by selective partial dissolution of some grains are present. The intercrystalline pores are typically triangular and occur between euhedral dolomite rhombs that range in size from 10 to 20 microns. The dolomite crystals have distinct iron-rich (ferroan) rims. Many of the intercrystalline pores are partly filled with fibrous authigenic illite, but overall pore size typically ranges from 1 to 5 microns. As expected, the first bench has the highest oil saturations in the Three Forks Formation, averaging 50% with a range from 30% to 70%. The second bench is also about 35 ft thick and consists of silty and shaly dolomite mudstones and rip-up clast breccias with euhedral dolomite crystals that range in size from 10 to 25 microns. Its color is quite variable, ranging from green to tan to red. The reservoir quality of the second bench data set appears to change based on proximity to the Nesson anticline. In the wells off the southeast flank of the Nesson anticline, the water saturation averages 75%, ranging from 64% to 91%. On the crest of the Nesson anticline, the water saturation averages 55%, ranging from 40% to 70%. NMR porosity is consistent across the entire area of interest - averaging 7.3% and ranging from 5% to 9%. Porosity observed from samples collected on the southeast flank of the Nesson Anticline is mainly as intercrystalline pores that have been extensively filled with chlorite clay platelets. In the water saturated southeastern Nesson Anticline, this bench contains few or no secondary pores and the iron-rich rims on the dolomite crystals are less developed than those in the first bench. The chlorite platelets in the intercrystalline pores reduce average pore size to 500 to 800 nanometers. The third bench is about 55 ft thick and is the most calcareous of the Three Forks benches with 20 to 40% calcite and a proportionate reduction in dolomite content near its top. It is also quite silty and shaly with a distinct reddish color. Its dolomite crystals are 20 to 50 microns in size and partly abraded and dissolved. Ferroan dolomite rims are absent. This interval averages 7.1% porosity and ranges from 5% to 9%, but the pores average just 200 nanometers in size and occur mainly as microinterparticle pores between illite flakes in intracrystalline pores in the dolomite crystals. This interval has little or no oil saturation on the southern Nesson Anticline. Unlike other porosity tools, the NMR tool is a lithology independent measurement. The alignment of hydrogen nuclei to the applied magnetic field and the subsequent return to incoherence are described by two decay time constants, longitudinal relaxation time (T1) and transverse relaxation time (T2). T2 is essentially the rate at which hydrogen nuclei lose alignment to the external magnetic field. The logarithmic mean of T2 (T2 Log Mean) has been correlated to pore-size distribution. In this study, we show that the assumption that T2 Log Mean can be used as a proxy for pore-size distribution changes is valid in the Three Forks Formation. While the NMR total porosity from T2 remains relatively consistent in the three benches of the Three Forks, there are significant changes in the T2 Log Mean from bench to bench. There is a positive correlation between changes in T2 Log Mean and average pore size measured on SEM samples. Study of a “type” well, QEP’s Ernie 7-2-11 BHD (Sec. 11, T149N, R95W, McKenzie County), shows that the 1- to 5-micron pores in the first bench have a T2 Log Mean relaxation time of 10.2 msec, whereas the 500- to 800-nanometer pores in the chlorite-filled intercrystalline pores in the second bench have a T2 Log Mean of 4.96 msec. This compares with a T2 Log Mean of 2.86 msec in 3rd bench where pores average just 200 nanometers in size. These data suggest that the NMR log is a useful tool for quantifying average pore size in the various benches of the Three Forks Formation.

scholarly journals Identification of Oil Reservoir Meeting Atypical Archie Phenomenon

2015 ◽  
Vol 8 (1) ◽  
pp. 354-357
Author(s):  
Shixiong Yuan ◽  
Haimin Guo ◽  
Yu Ding ◽  
Rui Deng
Keyword(s):  
Pore Structure ◽  
Water Saturation ◽  
Saturation Index ◽  
Oil Reservoir ◽  
Formation Water ◽  
Core Data ◽  
Hydrocarbon Reservoir ◽  
Pore Structures ◽  
Structure Index ◽  
Very High

According to core data, this paper studies variation of resistivity in different pore structures and wettability conditions. The results show that with the increase of pore structure index m, the resistivity will increase significantly when the saturation is constant. Similarly, with increasing saturation index n, the resistivity will also increase even with the same saturation. With fixed m and n, the calculated formation water saturation will be very high, resulting in hydrocarbon reservoir being ignored. This variation characteristic is significant for the identification of hidden reservoir with atypical Archie formula.

Utilizing Capillary Pressure Measurements and Water Saturation Logs to Determine Reservoir Quality in a Giant Middle Eastern Carbonate Field

2021 ◽  
Author(s):  
Bashar Alramahi ◽  
Qaed Jaafar ◽  
Hisham Al-Qassab
Keyword(s):  
Water Level ◽  
Capillary Pressure ◽  
Water Saturation ◽  
Middle Eastern ◽  
Free Water ◽  
Production Data ◽  
Reservoir Quality ◽  
Pressure Measurements ◽  
High Quality ◽  
Reservoir Facies

Abstract Classifying rock facies and estimating permeability is particularly challenging in Microporous dominated carbonate rocks. Reservoir rock types with a very small porosity range could have up to two orders of magnitude permeability difference resulting in high uncertainty in facies and permeability assignment in static and dynamic models. While seismic and conventional porosity logs can guide the mapping of large scale features to define resource density, estimating permeability requires the integration of advanced logs, core measurements, production data and a general understanding of the geologic depositional setting. Core based primary drainage capillary pressure measurements, including porous plate and mercury injection, offer a valuable insight into the relation between rock quality (i.e., permeability, pore throat size) and water saturation at various capillary pressure levels. Capillary pressure data was incorporated into a petrophysical workflow that compares current (Archie) water saturation at a particular height above free water level (i.e., capillary pressure) to the expected water saturation from core based capillary pressure measurements of various rock facies. This was then used to assign rock facies, and ultimately, estimate permeability along the entire wellbore, differentiating low quality microporous rocks from high quality grainstones with similar porosity values. The workflow first requires normalizing log based water saturations relative to structural position and proximity to the free water level to ensure that the only variable impacting current day water saturation is reservoir quality. This paper presents a case study where this workflow was used to detect the presence of grainstone facies in a giant Middle Eastern Carbonate Field. Log based algorithms were used to compare Archie water saturation with primary drainage core based saturation height functions of different rock facies to detect the presence of grainstones and estimate their permeability. Grainstones were then mapped spatially over the field and overlaid with field wide oil production and water injection data to confirm a positive correlation between predicted reservoir quality and productivity/injectivity of the reservoir facies. Core based permeability measurements were also used to confirm predicted permeability trends along wellbores where core was acquired. This workflow presents a novel approach in integrating core, log and dynamic production data to map high quality reservoir facies guiding future field development strategy, workover decisions, and selection of future well locations.

Developing a reliable height function from the J-Leverett parameters to populate water saturation: a case study

2015 ◽  
Vol 55 (1) ◽  
pp. 291
Author(s):  
Bert Filippi ◽  
Bahman Joodi ◽  
Mohammad Sarmadivaleh
Keyword(s):  
Extreme Values ◽  
Water Saturation ◽  
Dynamic Modelling ◽  
Free Water ◽  
Height Function ◽  
Clay Content ◽  
The North ◽  
The North Sea ◽  
Capillary Pressures

Populating water saturation is a critical step in dynamic modelling. This work introduces a different height function that equates directly with the Leverett-J formula. In doing so, the model initialises under quiescent conditions without the need for end-point scaling. The resulting water saturation is a function of permeability, porosity, clay volume and height above the free water level. The Vcl—or clay content—is an important feature in this formulation because it compensates between extreme values of permeability and porosity. This peer-reviewed paper describes how a single height function was sufficient to match the log-derived water saturation for all wells in the Coracle sand of the Surprise Field in the North Sea. The process involved fitting a simple height formula, with the least possible parameters, to the J-function calculated from all the special core analysis (SCAL) data. These parameters were then tuned to match the log-derived water saturation. This technique was subsequently used in other fields where a single height function, which honoured the measured capillary pressures, accurately matched water saturation in all of the wells.

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