Subsurface Interpretation

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FINAL PROJECT REPORT

ON

VALIDATION OF WELL LOG INTERPRETATION OF THE

HYDRATE BEARING SANDS OF THE PRUDHOE BAY OILFIELD

IN THE ALASKA NORTH SLOPE

BY

TAIWO AJAYI

SUBMITTED TO DR TOM WILSON

PROFESSOR, DEPARTMENT OF GEOLOGY

WEST VIRGNIA UNIVERSITY

IN PARTIAL FULFILMENT OF THE REQUIREMENT OF THE COURSE

“COMPUTER-AIDED SUBSURFACE INTERPRETATION” (GEOL 510)

DECEMBER 2013


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Table of Contents

Abstract ........................................................................................................................................................ iv

Chapter 1: Background ................................................................................................................................. 5

Natural Gas Hydrates: Nature and Significance ........................................................................................ 5

Geology of Alaska North Slope Hydrate Accumulations ........................................................................... 8

Eileen Trend .............................................................................................................................................. 9

Stability of Hydrates ................................................................................................................................ 10

Scope of Work ......................................................................................................................................... 11

Chapter 2: Methods .................................................................................................................................... 12

Database ................................................................................................................................................. 12

D and C Formations – Driller’s Picks ....................................................................................................... 13

Well Path Design and Well Log Integration ............................................................................................ 13

Well Sections and Correlations ............................................................................................................... 16

Chapter 3: Interpretation and Application of Results ................................................................................. 22

Chapter 4: Conclusions ............................................................................................................................... 27

Bibliography ................................................................................................................................................ 28


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List of Figures

Figure 1: Naturally Occurring Hydrates (3).................................................................................... 7

Figure 2: Map showing the Eileen and Tarn Trends (7) ................................................................. 9

Figure 3: Hydrate Stability Zone in the Prudhoe Bay Region. ..................................................... 10

Figure 4: Penetrated L-Pad Wells in the Prudhoe Bay (7)............................................................ 12

Figure 5: Surface Map of the Top of D Sand................................................................................ 14

Figure 6: Surface Map of the Top of C Sand ................................................................................ 14

Figure 7: D and C Tops in Comparison with the Existing West-East cross section of the Prudhoe

Bay L-pad Region ......................................................................................................................... 15

Figure 8: Surface Maps with Wells and Well Logs ...................................................................... 16

Figure 9: Selected Well Sections .................................................................................................. 17

Figure 10: Correlation of L-106 Well Log ................................................................................... 17

Figure 11: Central W-E Cross Section.......................................................................................... 19

Figure 12: Central N-S Cross Section ........................................................................................... 19

Figure 13: East N-S Cross Section................................................................................................ 20

Figure 14: West N-S Cross Section .............................................................................................. 20

Figure 15: SW - NE Cross Section ............................................................................................... 21

Figure 16: NW - SE Cross Section ............................................................................................... 21

Figure 17: Well Log Interpreted Surface of D Sand Top ............................................................. 22

Figure 18: Well Log Interpreted Surface of C1 Sand Top............................................................ 23

Figure 19: Well Log Interpreted Surface of C2 Sand Top............................................................ 23

Figure 20: Well Log Interpreted D Top and Bottom with the D Sand Isochore .......................... 25

Figure 21: Well Log Interpreted C1 Top and Bottom with C1 Sand Isochore ............................. 25

Figure 22: Well Log Interpreted C2 Top and Bottom with C2 Sand Isochore ............................. 26

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Abstract

The emerging possibilities with the exploration of gas hydrates as an unconventional source of

energy have spurred many objectives for research studies going on in this area. One of these isthe U.S national hydrate research program whose primary goal is to determine the commercial

viability of gas production from hydrate reservoirs.

This study aims to improve the existing interpretations of hydrate bearing sands found in the

Sagavanirktok formations of the Prudhoe Bay Region of the Alaska North Slope (ANS). Themain objective of this study is to validate or question existing interpretations of the L-pad

vicinity of the Prudhoe Bay region in order to build a more realistic geocellular model to support

an on-going flow simulation of methane gas production from its hydrate-bearing sands.

Three main production target sands have been identified – labelled E, D and C sands, in

increasing order of stratigraphic depth but this study focuses only on the D and C sands.Validation of the interpretation of E and D sands was done in a separate study. Surface maps and

well log correlations were made from data obtained from USGS using Petrel.

Results are indicative of features supporting an already interpreted existence of an almost

vertical N-S oriented fault bounding the hydrate sands of the Prudhoe Bay Region to the West.Well log correlations also revealed the existence of a subdivision of the C sand, namely, C1 and

C2.

Sand intervals between the hydrate layers are characterized with low permeability-high shale

content formations. Isochores, generally, were indicative of uniform lateral continuity but

showed some significant increase in thickness near the L-Pad vicinity and in the south eastregion. These areas may be favorable sites for gas production tests.

A seismic survey would be very much desired to have a better understanding of the extension of

the sand formations down dip of the Prudhoe Bay. Also, future work will also seek to investigatethe best well completion technique and gas recovery methods in order to maximize yield andminimize production costs.


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Chapter : Background

Natural Gas Hydrates: Nature and Significance

Natural gas hydrates are crystalline solids composed of water and gas. The gas molecules

(guests) are trapped in water cavities (host) that are composed of hydrogen-bonded water

molecules. Typical natural gas molecules include methane, ethane, propane and carbon dioxide

(1).

It is an already established fact that huge volumes of the world’s natural occurring methane are

trapped in gas hydrates. Even the most conservative estimates of the total quantity of gas trapped

in hydrates may surpass by a factor of two, the total fuel fossil reserves (2). A frequently quoted

estimate of the global methane hydrate resource is 20,000 trillion cubic meters, or about 700,000

Tcf. However, only a small portion of this enormous resource is likely to be harvested as an

energy fuel. If existing and new technologies can be applied economically to the development of

methane hydrate as a source of natural gas, the U.S. could significantly decrease its reliance on

foreign energy supplies (3).

In nature, gas hydrates occur both in the permafrost regions and in the marine sediments in the

oceans and deep lakes where pressure-temperature conditions are suitable and where sufficient

methane is delivered to the zone of hydrate stability in the uppermost sediments (2). Naturally

occurring methane hydrates can be found in both terrestrial and marine environments. Terrestrial

deposits have been found in polar regions, hosted in sediments within and beneath the

permafrost, while marine occurrences have been found mainly in sediments of the Earth’s outer

continental margins. Generally, hydrates form where there is a source of a hydrate forming gas

(e.g methane), free water and suitable pressure and temperature conditions. High pressure and


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low pressure favor hydrate formation. The methane that is captured in the methane hydrate may

have been formed by biogenic or thermogenic processes (3).

Biogenic methane is the common by-product of bacterial ingestion of organic matter. This is the

same process that produces methane in swamps, and it occurs continually within buried

sediments all around the globe. Biogenic processes are capable of producing vast amounts of

methane and are considered to be the dominant source of the methane trapped in hydrate

accumulations in shallow seafloor sediments. Thermogenic methane is produced by the

combined action of heat and pressure over a long period of time on buried organic material. Over

time and with deep burial, organic-rich source beds are literally pressure-cooked, with the result

being the production of large quantities of oil and natural gas.

As illustrated in Figure 1, methane gas is supplied from its source (biogenic or thermogenic),

through faults which serves as passages to the bottom of the sea floor or permafrost where

hydrates are formed and subsequently accumulated.

Given the pressure-temperature relationship found in deep marine environments, it might seem

that hydrate could accumulate anywhere in ocean-bottom sediments where water depth exceeds

about 400 meters. However, very deep sediments are generally not thought to contain large

quantities of hydrate. The reason is that very deep oceans lack the high biologic productivity

needed to create the organic matter that generates methane, and they lack the rapid sedimentation

rates needed to deeply bury the organic matter. These conditions do exist along the continental

margins — areas where the continental shelf transitions to the deep ocean. As a result, this is

where large quantities of methane hydrate are thought to exist in the marine environment.


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Figure 1: Naturally Occurring Hydrates (3)

Assessments produced by the U.S. Geological Survey (USGS) have estimated that 85 trillion

cubic feet (tcf) of undiscovered, technically recoverable gas resources exist within gas hydrates

in the Alaska North Slope (ANS).

In the year 2000, the Methane Hydrate Research and Development Act was established to

support the U.S national hydrate research program whose primary goal is to determine the

viability of gas production from hydrate reservoirs. This involves obtaining geophysical data

from exploratory wells, performing flow simulations and performing field tests. However, the

success of this program cannot be isolated from a sound geological interpretation, which is very

crucial to the development of any prospect of any sort.

It is noted here that an appreciable amount of work has already been done on the Alaska North

Slope by various interpreters; this project work would then seek to carry out independent

interpretations with the following objectives:


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To use available data and logs to carry out a geological investigation of the occurrence of

gas hydrates in the Prudhoe Bay Unit (PBU) of the Alaska North Slope

To validate (or question) existing and provide additional interpretations from newly

acquired logs

To provide technical advice and recommendations on possible short-term production test

sites,

Make geological based analysis in order to recommend the completion techniques. This

involves the choosing the best gas recovery method (conventional depressurization,

thermal or chemical stimulation) and making decisions on the types of wells (horizontal

or vertical) with a view to achieving optimized production.

The aforementioned form the objectives for carrying out this study.

Geology of Alaska North Slope Hydrate Accumulations

The hydrate accumulations in the ANS have been known to occur within the Sagavanirktok and

sandstone formation (4). The Sagavanirktok formation, named by Gryc, Patton and Payne

(1951), crops out along the lower part of the Sagavanirktok River and consists mainly of red-

bed-type, poorly consolidated siltstone, sandstone, conglomerate and lignite (5). They consist of

non-marine to beach-type sediments with inter-beds of shale and coal.

Natural gas hydrate within ANS shallow sand reservoirs was first directly confirmed by data

acquired in the Northwest Eileen State-02 well drilled in 1972. Since then the hydrate

accumulations have been discovered known as the Eileen and Tarn Trends. It has been estimated

that gas hydrate in the ANS may contain an average of 16.7 Trillion cubic meters (590 TCF) in-

place gas resources (6). The current research is being focused on the Eileen trend.


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Eileen Trend

As illustrated in Figure 2, the Eileen trend span over the eastern part of the Kuparuk River, the

southern part of the Milne Point and the western part of the Prudhoe Bay oil fields. Estimates

indicate that the total gas in place interpreted within shallow sand reservoirs below the

production infrastructures within the Eileen Trends may be up to 0.93 Trillion cubic meters (33

TCF) (7).

Figure 2: Map showing the Eileen and Tarn Trends (7)

The Eileen gas trend has been described to compose of six laterally continuous gas hydrate

bearing sand units. This was interpreted from the wells penetrating the Eileen accumulation as

many of them had multiple-gas hydrate-bearing units with thicknesses ranging from 3 to 30 m

thick. (6). These six gas hydrate-bearing sedimentary units in the Eileen accumulation have been

identified with the reference letters A through F, in the order of decreasing stratigraphic depth.

Generally, all formations dip towards the East.


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Stability of Hydrates

Generally, hydrates are stable within the conditions of high pressure and low temperature

although geochemistry and the type of sediment also play a part in determining the equilibrium

conditions with respect to stability. In order to clearly understand the stability of hydrates, an

equilibrium phase diagram is usually plotted and Figure 3 depicts the phase diagram for hydrates

in the Prudhoe Bay region plotting the average temperature (avg T) data obtained from the Ignik

Sikumi well and hydrate dissociation temperature (Tdiss) against depth below sea level (6).

Figure 3: Hydrate Stability Zone in the Prudhoe Bay Region.

Note: The Ignik Sikumi well is vertical; therefore, Measured Depth (MD) is equal to True Vertical Depth (TVD)

The upper and lower intersections of the curves mark the top and bottom of hydrate stability

zone in the Prudhoe Bay Region. This means hydrates are not expected to be found at depths

shallower than 500 ft or at depths greater than 3000 ft. It is currently being postulated that the

extensions of hydrate accumulations to the east of the Prudhoe Bay Oilfield may be truncated by

the region where these formation tops intersect with the bottom of hydrate stability zone (6).


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Scope of Work

Within the Eileen trend, extensive experimental studies have been carried out on the hydrate

formations with data obtained from:

One well log and a seismic interpretation in the Mount Elbert site (located in the Milne

Point Oilfield)

95 exploratory wells in the L-Pad (located in the Prudhoe Bay Oil Field) site.

Recent well data within the L-Pad vicinity have spurred the need for further studies to be

conducted with a hypothesis of an extension of the boundary of the Eileen trend in the L-Pad

region. In order to support reservoir flow simulation of gas production from this region, a

reliable geo-cellular model is needed to be built; hence the focus of this project work is within

the L-Pad region.

Existing interpretation of the L-106 well log revealed high saturation of hydrates in the E, D and

C sands which now makes them the primary target sands. They also suggest that the C sand may

be separated by a low permeability shale formation, therefore dividing the C sand into two sub-

units – Upper C (C1) and Lower C (C2) sands (6).

It was also intended to use some recently acquired resistivity logs to improve the knowledge of

hydration distribution within the region. In this study, the C and D hydrate bearing sands were

investigated.


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Chapter 2: Methods

Database

As of now, available data from USGS indicates that 95 wells have penetrated the C, D and/or E

units from the surface locations on L-Pad (see Figure 4). Majority of these wells are deviated

from the vertical at shallow depths.

Figure 4: Penetrated L-Pad Wells in the Prudhoe Bay (7)

USGS data consist of the surface coordinates (x, y), measured depths (MD), true vertical depth

(TVD) of the well heads, intersections of the wells with the D and C sand formations and well

log files (with .las extension). These data were made available in a Microsoft Access Database

(.mdb) format were presented in the Alaska State Plane Coordinate System – Zone 4 with units

of US ft . Well header and well top files were sorted in MS Excel and saved as comma separated

value (ASCII encoded files) in line with the format required by Petrel.


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D and C Formations – riller’s Picks

A well header file was created by using well head coordinates in the USGS data and was

uploaded into Petrel. In similar fashion, driller’s picks of the D and C sand formations as

obtained from the USGS data as coordinates of the tops of the D and C sands, were uploaded as

well tops files.

Using Petrel’s Make/Edit Surface utility, the surfaces of the D and C sands were plotted using

the minimum curvature interpolation method. These surfaces are presented in Figure 5 and

Figure 6.

A cursory interpretation of the surface maps based on the driller’s picks reveals a very steep

topography at the western end of both the D and C surfaces as indicated by the high density of

contour lines in this region. This is a supporting feature for the original interpretation made by

USGS, of the existence of a vertical North-South oriented fault in this region.

Also, it is also noted that the upthrow side of the assumed fault, generally gently dips roughly

towards the north east, as expected from the already known geology of the region. The overall

structure can be closely compared to the existing interpreted West-East cross section of the

Prudhoe Bay L-pad region as illustrated by Figure 7.

Well Path Design and Well Log Integration

Deviated well paths were created using Petrel’s well path design tool by manually clicking to

join the well heads with the points of intersection with the D and C sands and the bottom-hole,

successively. It is noted here although the surface (x, y) coordinates of the bottom-hole of all the

wells were available, information on their total vertical depth (TVD) were very limited. In lieu of

this, bottom-hole TVD of 4,000 ft was assumed for all wells. Therefore, the well path created


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herewith is only a guided approximation and it was based on the fact that the available bottom-

hole TVDs from few wells was within that range.

Figure 5: Surface Map of the Top of D Sand

Figure 6: Surface Map of the Top of C Sand

Suggested Fault

Suggested Fault


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Figure 7: D and C Tops in Comparison with the Existing West-East cross section of the Prudhoe Bay L-pad Region

Suggested Fault


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The corresponding well logs were uploaded and associated with their corresponding wells and

the resulting structure is shown in Figure 8 below.

Figure 8: Surface Maps with Wells and Well Logs

Well Sections and Correlations

In making the well sections, only 20 out of the 95 wells were used. These wells were selected

based on the quality of the logs and their relative location to one another with respect to

maximizing the area of the region which can be effectively interpreted. Figure 9 shows the six

cross sections selected for interpretive correlation.

The logs available were Hydrate Saturation (SH), Water Saturation, Volume of Shale Content

(VSHC), Resistivity (RES), Gamma Ray (GR), Density (RHOB) and Total Vertical Depth

(TVDSS) and Sonic (DT). Only four wells had SH and VSHC logs, one of which is that of the L-

106 well shown in Figure 10. It is to be noted that, of all the logs available, L-106 well has the

best log quality (6).


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Figure 9: Selected Well Sections

Figure 10: Correlation of L-106 Well Log

Well Sections and orrelations

Central N-S Cross Section

SW-NE Cross Section

NW-SE Cross Section

West N-S Cross Section

East N-S Cross Section

Central E-W Cross Section

LEGEND


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For this reason, the SH log from the L-106 well was used to correlate signatures of hydrate

occurrence in other wells. Driller’s pick suggests that the L-106 intersects the D sand at TVDSS

of 1953 ft. From the log, high and positive value for SH within this vicinity of depth occurs at a

TVDSS of 1,955 ft (close agreement with the driller’s pick). The base of this high hydrate

saturation region is at a depth of 2006 ft TVDSS. This implies that the D sand in the L-106 well

is 51 ft thick. As seen in from other L-106 well logs, it can be seen that this region of high SH in

the L-106 well also corresponds to a region of low SHC, high RES and low GR. These now

become signatures of hydrate occurrence in wells not having SH log. These signatures were used

to produce the correlations shown in Figure 11 toFigure 16.


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Figure 11: Central W-E Cross Section

Figure 12: Central N-S Cross Section


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Figure 13: East N-S Cross Section

Figure 14: West N-S Cross Section


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Figure 15: SW - NE Cross Section

Figure 16: NW - SE Cross Section


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Chapter 3: Interpretation and Application of Results

From the well correlations, it was inferred that the D and C sands are separated by a high gamma

ray and high shale content formation. It can also be seen that the C sand is divided into two sub-

units C1 and C2, also separated by high shale content formation. These are consistent with the

existing interpretation of the region.

In order to have a clearer interpretation of the hydrate bearing formations and their distribution,

surface maps and isochores were generated using the well log picks and these are shown in

Figure 17, Figure 18 and Figure 19. These surfaces also have the same suggestive features as the

driller’s pick based surfaces in the sense that they support the possibility of a fault towards the

west end of the formations.

Also, within the upthrow side of the proposed fault, the southwest region have highs, most of the

central region are almost uniform with lows towards the east. This also confirms the gentle

dipping nature of the surfaces generally towards the east.

Figure 17: Well Log Interpreted Surface of D Sand Top


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Well Log Interpreted Top Surface of the C1 Sand

Figure 18: Well Log Interpreted Surface of C1 Sand Top

Figure 19: Well Log Interpreted Surface of C2 Sand Top


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Isochores of the D, C1 and C2 sand formations were also plotted and are shown in Figure 20,

Figure 21Figure 22. The D sand isochore suggests that the southeast of the region has the highest

thickness hydrate bearing sands. The C1 and C2 isochore infers a high thickness of hydrate

formation both near the region of the L-pad and the southeast part. The thickness of hydrate

formation in the C2 sand is almost uniform.

Target production areas, typically, are warm regions and regions with high hydrate thickness.

Based on hydrate formation thickness, this implies that wells in the southeast region, (i.e. wells

penetrating the formations near L-220 and Well 1) and those near L-106, L117 and would be

good producers. However, due to drilling and operational costs of horizontal wells, as would be

required if production is to be carried out in the south east region, production from wells in the

neighborhood of L-106 may be preferred.

Based on temperature of formation, the hydrates of the D sand, which is the coldest formation,

are the most stable compared with hydrates of C1 and C2, hence are the least favorable targets

for production in terms of the ease to dissociate and release methane. From the foregoing, the

optimum target for methane production would be from the C sands with wells penetrating them

within the vicinity of wells L-114, L-115, L-117, L-118 and L-106.


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Figure 20: Well Log Interpreted D Top and Bottom with the D Sand Isochore

Figure 21: Well Log Interpreted C1 Top and Bottom with C1 Sand Isochore


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Figure 22: Well Log Interpreted C2 Top and Bottom with C2 Sand Isochore


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Chapter 4: Conclusions

Interpretation from this study in close agreement with the existing well log inferred

interpretation. The nature of the inferred existence of the western fault has not been fully

understood. Questions such as whether there is “communication” or any connection between the

hydrate sands across the faults still remain unanswered.

In order to get more insight to the lateral extension of the hydrate formations, especially in the

down dip eastern region of the Prudhoe Bay Oilfield, a Seismic survey area is very much desired.

From this, more information on the continuity of hydrate formations and any other existing faults

/ closures can be obtained.

Reservoir flow simulations would further determine the optimum completion technique for gas

production i.e. whether vertical or deviated wells would be desired. Also, future work will also

seek to investigate any one or combination of depressurization, thermal stimulation, inhibitor

stimulation and CO2 sequestration, in order to determine the best gas recovery technique in terms

of yield and commercial viability.


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