Photo by Bayonle Omoniyi
Sheet thin-bedded-to-very thick-bedded turbidites Silurian Mynydd Bach Formation
Aberystwyth Grits Group Ceredigion (Mid Wales), UK
This chapter focusses on the data and a range of methods used for this research. In particular, it discusses the ‘attribute indices’ method, and basic principles and techniques that underlie core-based porosity and permeability measurements, reservoir modelling, and flow simulation as used in this thesis. References have been collated at the end of the thesis.
40 3.1 DATABASE
3.1.1 Core
For this research, cores revered from nine wells in the North Brae Field, United Kingdom Continental Shelf of the North Sea, were studied. These wells have high core recovery (average, 75-100%), and cored intervals comprise TBT/VTBT proportions that range from 10% (e.g. 16/07a-B1) to 100%. In the nine wells, a total of 5,851 ft (1,783.4 m) were logged and described, of which 1,107 ft (337.4 m) was logged at 1:10 scale for a more detailed study (Chapter 4). In addition to the cores from the North Brae Field, 16,275 ft (4,960.6 m) of cores were logged and described from eighteen wells covering Pierce, Starling, and Fram Fields, United Kingdom Continental Shelf of the North Sea.
The data provided geological attributes of TBT/VTBT facies within a typical channelised setting (Pierce Field), proximal lobe setting (Starling Field), and distal lobe setting (Fram Field). In total, 22,126 ft (6,744.0 m) of cores were logged for this research and the insights gained were built into this thesis, particularly, Chapters 2, 4 and 8.
It is important to note that the cores from the North Brae Field were provided by Marathon Oil Company, and those from Pierce, Starling, and Fram Fields were provided by Shell Oil Company. Both companies are located in Aberdeen, United Kingdom. Other cores from the North Brae Field were studied at the National Core Repository, Keyworth, United Kingdom (Figure 3.1; A, B).
3.1.2 Outcrop
Outcrop studies offer invaluable insight into the impact of (sedimentary) heterogeneities on fluid flow (Prosser & Carter, 1997; Slatt et al., 1998; Browne & Slatt, 2002; Larue, 2004; Sullivan et al., 2004; Pedersen et al., 2007; Labourdette et al., 2008; Davis et al., 2010; Funk et al., 2012; Amy et al., 2013; Eschard et al., 2014; Pickering et al., 2015).
Two major fieldwork programmes were undertaken to help build a robust attribute database for TBT/VTBT facies in ancient systems. The first was a comprehensive 25-day fieldwork programme in Mid Wales, United Kingdom, covering Trefechan Formation and Mynydd Bach Formation, both in the Silurian Aberystwyth Grits Group.
The two formations consist of deepwater turbidite sandstones in addition to some shallow marine deposits. In Mynydd Bach Formation, turbidite sandstones comprise thick-bedded and largely, structureless sandstones, with interthick-bedded TBT/VTBT facies and
41 A.
B.
Figure 3.1. Selected photographs showing (A) core shelves, National Core Repository, BGS, Keyworth, and (B) a typical core study section. Study of beds with thickness ranging from <1cm to 10 cm can be very challenging indeed. For this research, a total of 22,126 ft (6,744 m) of cores and over 892 ft (272 m) of outcrops were logged for this research, totalling 23,018 ft (7,016 m). To put in context, the total section logged for this research covers the length of 78 standard football pitches.
42
turbidite mudstones. Trefechan Formation, conversely consists of interbedded mudstones and sandstones that are largely thin-to-very thin-bedded (Figure 3.2). The deep understanding gained from the preliminary interpretation of results provided significant information about the general characteristics of TBT/VTBT, especially on the subject of their attributes and attribute indices (Chapters 2, 3, 6 and 8), and were used to inform the geometrical parameters upon which the related facies models were constrained (Chapters 5 and 7). The complete preliminary results are set aside for future research purposes, but the sedimentary logs are provided in Appendix A.
The second fieldwork programme was undertaken in Zumaia, a village in the Basque Country, Spain. The 5-week intensive fieldwork was scheduled to develop the Lateral Connectivity Index (LCI), the lateral component of the Sand Connectivity Index (SCI). Within this period of five weeks, approximately 597 ft (182.0 m) interval was logged and described. This interval constitutes the siliciclastic section of the Itzurun Formation (Figure 3.3). TBT/VTBT attribute data, including bed thickness data, were collected over the period of study. The bed thickness data collected are reserved for research in the future, but the attribute data were used to prepare the results presented in Chapter 6 of this thesis.
3.1.3 Wireline logs
Wireline logs, comprising gamma ray, neutron, density and sonic from ten wells in the North Brae Field (B27, B14, B1, B7, B8, 16/07a-19, 16/07a-B17, 16/07a-B10, 16/07a-7) were studied for this research. To aid facies interpretation and well correlation, cores recovered from the wells were matched with wireline logs. Uncertainty in facies interpretation was significantly reduced by studying wireline logs from seven wells in Pierce and Starling Fields to delineate log character in TBT/VTBT intervals.
43
Figure 3.2. Deepwater turbidite succession at Clarach, Silurian Trefechan Formation, Aberystwyth Grits Group, Wales. The succession comprises interbedded turbidite mudstones and sandstone and are largely thin-bedded.
44
Figure 3.3. A photograph showing a deepwater turbidite succession (Eocene Zumaia section) in the Itzurun Formation, Basque Country, Northern Spain. Approximately 597 ft (182 m)-interval of this section was logged and described for this research.
45 3.2 METHODS
3.2.1 Turbidite attributes
The principal sedimentary attributes used to characterise and discriminate between different TBT/VTBT systems are listed below.
(a) Facies: nature of turbidite facies present; quantification of the relative proportion of TBTs with Bouma sequences and VTBTs with Stow sequences.
(b) Sedimentary structures: recognition of full and partial Bouma or Stow sequence types, and top/mid/basal divisions present.
(c) Facies associations: the grouping of TBT and VTBT facies in order to represent the succession (and parts of the succession) more succinctly than through individual facies; the associated facies present in succession and their relative proportion is also noted.
(d) Bed thickness: examination of bed thickness, including full turbidites (i.e. sand-mud graded beds); quantification of the mean thicknesses of sand and sand-mud parts of beds.
(e) Vertical sequences of bed thickness: a broader perspective of the turbidite succession within mega- and meso-sequences, either from visual inspection or determined from statistical analysis; particular focus on the micro-sequences within the TBT/VTBT package.
(f) Sand-shale or sand-mud ratio: quantification of the relative proportion of sand and mud within a given sequence; this is a derivative measurement of the standard net-to-gross ratio used in the petroleum industry.
(g) Connectivity: characterisation/measurement of the sand and shale geometry, sand/shale lengths, and number of sands/silts in direct contact with one or more other sands/silts.
46
(h) Sediment texture: determination of the mean grain size of sands, mean grain size of silts, and mean grain size of the interbedded mud divisions; other textural attributes, in particular, sorting and skewness can also be quantified.
(i) Sediment composition: mineralogical and/or geochemical make-up of the different sediment fractions (sand/mud); siliciclastic, bioclastic, volcaniclastic, chemoclastic or mixed turbidite types.
(j) Sediment fabric: the alignment and disposition of individual grains and particles with respect to each other; applicable to both sand and mud fractions.
3.2.2 Attributes indices
The set of TBT/VTBT attributes discussed in previous subsection can be quantified using four fundamental variables, referred to as attribute indices. The indices were originally developed from cores recovered from nine wells in the North Brae Field, and later extended to wells in the Pierce, Starling, and Fram Fields within the Palaeocene Forties Formation, for complementary application. For calculating dimensionless attribute indices, bed thickness cut-off is 1cm.
3.2.2.1 Facies Net-to-Gross Index
The facies Net-to-Gross Index (NGI) recognises the distinctive TBT/VTBT facies within the constituent facies of a turbidite sequence. It particularly expresses the standard net to gross sand value commonly used to evaluate reservoir intervals, and indicates the relative proximality of deposition and/or energy and competence of turbidity current. It is calculated using Equation 3.1.
NGI NT
GT (3.1)
NT and GT are net and gross thicknesses, respectively, for the particular facies association interval being considered.
47
NGI varies from 0 to 1. Low NGI values represent low net-to-gross for the facies association, whereas high NGI values indicate high net-to-gross.
3.2.2.2 Sand Connectivity Index
The Sand Connectivity Index (SCI) is a new approach developed to estimate spatial connectivity (also referred to in ensuing chapters as connectivity) in TBT/VTBT-associated deepwater architectural elements. Although pressure data, well-test data, and production data are all different ways of estimating connectivity, they indirectly indicate connectivity between fluid contacts (pressure data) or injector well to producer well (well test and production data). By contrast, the spatial connectivity indicated by Sand Connectivity Index (SCI) is an attribute index that provides a quantitative estimate of the connectivity between primary (turbidite) reservoir facies and associated TBT/VTBT facies. It is derived from the nature of bed/lamination cross-cutting relationships, and it serves as an important discriminator for predicting lateral and vertical continuity and connectivity in TBT and VTBT facies associations, and in related primary reservoir sands. It provides a more rigorous predictor of TBT/VTBT sand reservoir potential than conventional sand net to gross. SCI can be calculated from Equation 3.2.
SCI VCI LCI x NGI (3.2)
Where NGI refers to facies Net-to-Gross Index, VCI is Vertical Connectivity Index, and LCI is Lateral Connectivity Index. Both VCI and LCI are defined as follows:
Vertical Connectivity Index
The Vertical Connectivity Index (VCI) was previously called Sand Connectivity Index (Omoniyi et al., 2013; Omoniyi et al., 2014; Omoniyi et al., 2015). The VCI expresses apparent connectivity in a wellbore or over a vertical interval in an outcrop section. It is a product of NGI and Vertical Connectivity Factor (VCF). That is:
VCI NGI x VCF (3.3)
NGI is mathematically defined in Equation 3.1 and VCF is calculated as follows:
48
VCF S/S
S S S NS
(3.4)
where S/S is the proportion of sand overlying sand, and S/NS represents the ratio of sand overlying non-sand/non-silt lithology.
VCI varies from 0 to 1. Low VCI values imply low apparent vertical connectivity and high VCI values indicate high apparent vertical connectivity.
Lateral Connectivity Index
The Lateral Connectivity Index (LCI) refers to the apparent lateral connectivity of respective TBT/VTBT facies and related sandbodies within the interval being considered.
In other words, it is defined as:
LCI h X⁄ x n
h X⁄ x n (3.5)
where h & h are interval thicknesses at two locations (1 and 2);
X is the distance separating the two locations; and
n & n represent number of beds within the interval under consideration at location 1 and location 2, respectively.
LCI varies from 0 to 1. Low LCI values imply low apparent lateral connectivity and high LCI values indicate high apparent lateral connectivity.
3.2.2.3 Facies Ratio Index
The Facies Ratio Index (FRI) is derived from the proportion of TBT beds to the sum of TBT and VTBT beds in a characteristic facies association. It is therefore distinctive of different depositional environments, proximal to distal relationships and/or near-to-far channel location. It compares to Bouma/Stow sequence combination and selected facies ratios. That is:
49 FRI nTBT
∑ n TBT; VTBT (3.6)
nTBT refers to number of TBT beds in a distinctive facies association being considered, and ∑n TBT; VTBT is the sum of TBT and VTBT in the facies association. FRI ranges from 0 to 1 and it is indicative of the energy condition prevalent during sediment transport and subsequent deposition.
3.2.2.4 Sediment Textural Index
The Sediment Textural Index (STI) is derived from the mean grain-size property of all the TBT-VTBT facies in the specific facies association being considered. In particular, it is a measure of the difference in mean grain size between the coarser-grained (sandstone-siltstone) beds and the finer-grained (mudstone-rich) interbeds. It therefore takes into account the relative ease with which fluid can migrate through and be stored within the mudstone interbeds compared with the sandstone beds. It can provide insight into sediment transport, depositional history and sediment maturity.
The STI is calculated by taking the reciprocal of mean grain size in phi units (δm) of all the mud-rich interbeds minus the mean grain size in phi units (δs) of all the sand-rich beds in the facies association being considered. In each case, the nearest whole number phi unit is used. This is then multiplied by the NGI in order to account for the relative thickness of sandstone versus mudstone. This therefore becomes:
STI 1
δm δs x NGI (3.7)
STI ranges from 0 to 1, where values closer to 0 represent a large difference between sand and mud mean grain size and relatively thicker mudstone interbeds, whereas values closer to 1 represent a small difference between the sand and mud mean grain size and relatively thinner mudstone interbeds.
3.2.3 Laboratory-based property measurements of TBT/VTBT facies plugs
The variability of reservoir properties of TBT and VTBT is usually difficult to predict, particularly, in the presence of sparse data. Prediction of these properties in hydrocarbon
50
reservoirs is critical in clastic turbidite reservoirs with a significant proportion of TBT and VTBT facies, and it impacts prospect evaluation, reserve estimation, reservoir development and depletion strategy. Laboratory-based measurements of core plugs provide the most direct way to determine rock mechanical data (Ameen et al., 2009).
However, these measurements are mostly replaced with measurements derived from wireline logs because of the high cost of coring wells. The two properties of interest to this research are porosity and permeability. These properties were measured on representative core plugs and, the results were used where there were no cores for laboratory-based measurements (Chapter 6), and to quality-control the measured properties used in Chapters 5 and 7. Laboratory-based porosity measurements were also correlated with wireline log-derived porosity (Chapter 4) in order to establish a porosity trend for uncored intervals.
3.2.3.1 Sample preparation
Forty eight cylindrical core plugs (hereafter referred to as plugs) were acquired from a North Brae Field well, 16/07a-B27, using Eibenstock EBM 250\2P coring machine with 25.25 mm (~1.0 in) diameter drill (Figure 3.4). Coring was carried out at discrete points to include the six TBT/VTBT facies associations identified in the North Brae Field. The resultant plugs were accurately trimmed, at both ends, to desired dimensions, using a Cutrock GSP 1463 trimming saw (Figure 3.5). Water supplied from a tap was used as a lubricant during coring and trimming of plugs. The trimmed plugs (Figure 3.6) were appropriately labelled using a permanent marker, and kept on a flat surface within the laboratory, to dry for six days.
3.2.3.2 Principle and procedure for porosity measurement
On the seventh day, a digital vernier caliper was used to measure plugs’ dimensions (i.e.
diameter and length). For each measurement, three readings were taken and the average value was calculated and recorded. This average value enhanced precision of dimensions measured. Each plug was then placed in the specimen chamber of a helium gas expansion Porosimeter MK II (Figure 3.7, A). The porosimeter has an output channel, which provides an opportunity for interfacing with a computer for calibration, data storage and analysis. This equipment is capable of porosity measurements over a range of different
51
Figure 3.4. A photograph showing an Eibenstock EBM 250\2P coring machine, being safely operated at Geomechanics Workshop (HWU, Edinburgh). The machine was powered by electricity, and coring core slab was done by gently lowering the drill using the drill control. Water was supplied through a hose connected to a tap, and served as a lubricant to ease coring.
52
Figure 3.5. A photograph showing a Cutrock GSP 1463 trimming saw, being safely operated at Geomechanics Workshop (HWU, Edinburgh). The machine was powered by electricity, and trimming of plugs was done by carefully turning the ‘control wheels’.
Water was supplied through a hose connected to a tap, and served as a lubricant to ease trimming.
53 Photo was taken by Bayonle Omoniyi
Figure 3.6. A photograph showing selected plugs cored from 16/07a-B27, North Brae Field.
54
plug sizes without modification and can be easily calibrated. It operates on the principle of Boyle’s Law (Figure 3.7, B). This law states that, for an ideal gas, at constant temperature, the multiple of its pressure and volume is a constant (Equation 3.8).
P V P V (3.8)
The gas transfer technique involves the injection of helium gas into the space with known volume. It is then allowed to expand into another space also with known volume. By placing a plug of unknown grain volume in the second space and measuring the final pressure of the helium in the space, the unknown grain volume V of the sample can be calculated using Equation 3.9:
V 118.12 1720.32
P V (3.9)
where P is pressure (in Pascal) of the plug being measured and, V is the filler volume (cubic centimetre). The filler volume is the known (cylinder) volume where the filler is used. Where no filler is used, filler volume is zero. The pressure, P, is read out from the helium regulator meter (see the dotted red arrow in Figure 3.7, A).
For each plug placed in the specimen chamber (see the thick red arrow in Figure 3.7, A), its grain volume was calculated by the difference in final pressure between the initial pressure (when the chamber is empty) and final pressure (with the plug in the chamber). When the key is open to allow gas supply, it (helium gas) penetrates all the pore spaces that are available for flow. Consequently, the volume taken up by the plug inthe chamber is that, which is occupied by the grains and the pores that are not connected with the plug surface. Thus, the porosity calculated through this method is the effective porosity (not total porosity). According to Stocks (2009), effective porosity is a measure of pores that are in communication such that fluids can pass through the pore system.
For measurement of the forty-eight plugs, the gas supplied was allowed to settle in the core chamber, so the first pressure reading was not recorded. Subsequently, three pressure readings were taken and their average was recorded to ensure precision.
55 A.
B.
Figure 3.7. (A) A photograph showing a Helium gas expansion Porosimeter MK II that was used to measure porosity of representative TBT/VTBT plugs. The red arrow points to core chamber and dotted arrow marks helium regulator meter from which the pressure value is read. (B) A sketch showing the operating principle upon which the porosity measurement is based.
56
3.2.3.3 Principle and procedure for permeability measurement
The permeability of the plugs was measured using EPS Nitrogen Gas Permeameter. This equipment was designed to eliminate potential sources of error and inaccuracy. It was connected to two nitrogen supplies to obtain desired confining pressure (300 pounds per square inch, psi) using a 0-100 psi regulator (Figure 3.5). All permeability measurements were made under a backpressure flow mode to provide accurate control of core pressure and flow rate, and to maintain laminar flow rates, particularly in high-permeability plugs.
This mode is preferred to flow under atmospheric pressure (i.e. forward flow) because it restricts the development of non-Darcy flow, over a variety of flow/pressure conditions.
However, for this mode (backpressure flow), a transducer zero shift correction was carried out. The zero shift is a phenomenon that is caused by unequal stresses acting on the diaphragm of the transducer when a pressure, greater than the ambient calibration pressure, is applied equally to both sides of the diaphragm (EPDS User manual). The differential and gauge transducers of the instrument were calibrated by a Geomechanics specialist (Sally Hamilton).
The permeability of each of the forty-eight plugs was measured by gently placing it in the core sleeve so that it lies horizontal and fits easily into the sleeve and allows adequate clearance for loading. Care was taken to ensure that the plug was centrally located within the coreholder (red arrow in Figure 3.8). The fluid distributors were located against the plug face and locked in position by evenly hand-tightening the two locknuts, located at both ends of the core sleeve. Approximately the same amount of thread must be evident on each locknut to prevent gas leakage. Care was also taken to ensure that fluid distributors did not move within the core sleeve. The procedure for operating the instrument (Figure 3.9) was then carefully followed.
The operational principle is based on the fact that a gas is compressible, whereas
The operational principle is based on the fact that a gas is compressible, whereas