JOHN HUDSONELIZABETH WYANT

DR. MIGUEL BAGAJEWICZ

APRIL 29, 2008

Economic Potential of Stranded Natural Gas

Hydrates

Problem

Can gas hydrates be exploited economically? What are hydrates and where are they located? What research is going on and what are the

problems? What is the time line for the project? Where are the wells going to be drilled and how

many? What kind of production can be expected? What markets can the natural gas from hydrate

be sold in? What is the most economic option to transport

the natural gas to the sales market?

Why Gas Hydrates?

Conventional oil and gas resources are being depleted

Alternatives are becoming more economical Market prices (NYMEX)

$9.501/MMBTU on 3/5/08 $7.719/MMBTU on 2/1/08

Large proven reserves Estimated 5,000 to

12,000,000 trillion cubic feet (TCF)

3

Natural Gas Hydrate

What is it? Methane molecule surrounded by water/ice Found at 32 - 41 F and around 50 atm Unstable at atmospheric conditions 168 standard cubic feet of natural gas per

cubic foot of hydrateWhere are they located on land?

Arctic and Antarctic regions At a depth between 1000 – 5750 feet Common above conventional gas reservoirs

Where to Drill?

Kamchatka Peninsula, Russia

Research and Potential Problems

A Canadian and Japanese team worked on drilling Mackenzie Delta

Continuous flow for 6 days

Other countries such as The U.S., India, Japan and China are trying to find them.

Potential Problems include: Produced water

1 cubic foot per 168 cubic feet of natural gas Produced sediment

Project Timeline

Tasks 1 2 3 4 5 6 7 8 9 10 11-30

Have Logistic for both the LNG/ Pipeline started                      

Seismic: 5 person team (6-8 weeks) $54                    

Order Materials for Pipeline/LNG facility                      

Find crew and begin measures to house and feed them                      

Ship Intial Equipment: Build Pad 1                    

Drill 1st Well, perform core analysis, and other analysis                    

Cap well until Pipeline/LNGbuilding is completed                      

Build Pipeline/LNG: will take 3 - 6 years (Assume 4 years)                      

Start building facilities for each location (approx. 2 months per facility)                      

Drill all other wells                      

Start wells to sells                      

• If seismic data renders negative project is stopped. Loss is $54 million• With a go-ahead, production would start at year 9. • Net present worth of investment during first 9 years = -$5 to -25 Billion

Assumptions

Potential problems Large amounts of produced water Produced sediment (land slides)

Assuming: An ideal situation. (i.e.none of the potential problems occur). Natural gas hydrates are found at 2000 – 4500 feet

below that surface. Assume 4 total daily natural gas production rates (million standard cubic feet, MMscf) 130, 195 , 260 and 390 MMscf

Drilling Specifics

Drilling Operation

6 basic steps

1. Shoot seismic (Geology)

2. Prepare site for drilling

3. Drill well4. Log well5. Complete well6. Produce well

10

Seismic Information

11

Site Preparation

Build roadsPrepare groundTransport and

install equipment (rig up)

Drill well

12

Drilling Well

ComplicatedDangerous

Steps to drilling1.Drill into ground2.Set casing and

cement3.Repeat until

finished4.Prepare for

completion 13

Horizontal Drilling

14

Coring

Can look at the subsurface

Special drilling operation

15

Logging Well

Done after drillingDetermines

subsurface composition

16

Completions

Communication with the formation

Three steps Perforation Fracturing Install production

equipment

17

18

Kamchatka Peninsula, Russia

Drilling Location 3000 sq. miles of land

Important Locations

Locations 4 wells per pad 1 mile between

each pad

Drilling Plan

Shoot seismic Drill the first well and take coring samples

Vertical well Each well at different depths

2500 feet, 3000 feet, 3500 feet, and 4000 feet Average production per well is 882867 standard cubic

feet per day

Maximum production per well (scfd) 882867      

Needed Production (MMscfd) 130 195 260 390

Number of wells 147 221 294 442

Number of locations 37 55 74 110

Production Model

Methods of Production

DepressurizationThermal injectionMining

Production Model

Wiggins and Shah (OU) model (2001)

Reservoir Pressure Dissociation

Pressure

Flow Properties

Distance from well

• Based on continuity equation. • Uses dissociation kinetics.• Consider pressure drop in porous hydrate free rock.

0 10000 20000 30000 400000

100200300400500600700800

Radius, m

Pre

ssure

, psi

Description of Model

Assumptions: Darcy flow (laminar

flow) Radial flow Homogenous, isotropic

reservoir Hydrate dissociation at

interface

Limitations: Cannot model high flow

rates Cannot be used with

irregularly shaped reservoirs

Excel Calculations Snapshots

0 5000 10000 15000 20000 25000 30000 350000

100

200

300

400

500

600

700

800

1,000 SCMD (0.1 to 20 years)

Radius, m

Pre

ssure

, psi

R* increases from 2,000 m to 26,000 m over 20 years.

Re = 4,000

0 10000 20000 30000 40000 50000 60000 70000 80000350

375

400

425

450

475

500

525

550

575

600

625

650

675

700

5,000 SCMD (0.1 to 20 years)

Radius, m

Pre

ssure

, psi

R* increases from 5,000 m to 58,000 m over 20 years.

Re = 20,000

0 20000 40000 60000 80000 100000 1200000

100

200

300

400

500

600

700

800

10,000 SCMD (0.1 to 20 years)

Radius, m

Pre

ssure

, psi

R* increases from 8,000 m to 83,000 m over 20 years.

Re = 40,000

0 20000 40000 60000 80000 100000 120000 140000 160000 1800000

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

25,000 SCMD (0.1 to 20 years)

Radius, m

Pre

ssure

, psi

R* increases from 12,000 m to 130,000 m over 20 years.

Re = 100,000

Limits of Gas Flow

Flow changes from Darcy flow to non-Darcy flow after 25,000 SCMD Model does not work for high flow rates New model must be developed and used

Reservoir controls the maximum flow rate

Choke Flow (Flow Limits)

1 2 3 4 5 6 7 8 9 10 11 120.0

1,000,000,000.0

2,000,000,000.0

3,000,000,000.0

4,000,000,000.0

5,000,000,000.0

6,000,000,000.0

7,000,000,000.0

8,000,000,000.0

9,000,000,000.0

10,000,000,000.0

Maximum Flow Rate in Piping

Diameter, in

Flo

w R

ate

, m

3/d

Flow rate potential in piping is far greater than the reservoir can handle.

Wellhead Facilities

  Specs # Needed UOM Cost

Christmas Tree Max P: 10,000 psia 4 MM$ 0.2

Vertical 3-phase separator Flow rate: 100 MMscfd 2 MM$ 0.15

  Diameter: 5.3 m      

  Height: 8.5 m      

  Volume: 326 m3      

Compressors    

Pad 1 437.77 HP 1 MM$ 0.875

Pad 2 - ? 6771.51 HP 1 MM$ 13.543

Vertical Separator

Christmas Tree

Gathering System

The gathering system is not just located in one place.

Bring wells together to minimize pipe.

Transportation and Markets

Transportation Options Liquefied Natural Gas Pipeline

Three different markets Japan Mainland Russia China at a later date

Important Locations

LNG Facility

Liquefied Natural Gas

Gas Usage and Value By: Dr. Duncan Seddon

Total LNG Costs

0

1000

2000

3000

4000

5000

130 195 260 390

Gas Flow Rate (MMscfd)

Cos

t (M

M$)

Drilling

Surface Equipment

LNG Facility

Shipping

Regas Facility

Important Locations

Pipeline

Pipeline to Magadan, Russia, and Blagoveshchensk, Russia

Piping Network Simulation

Pipeline Economics

Subsea Pipeline Economics By: Palmer

Total Pipeline Costs

0

1000

2000

3000

4000

5000

6000

130 195 260 390

Gas Flow Rate (MMscfd)

Cost

(MM

$) Drilling Costs

Surface Equipment Cost

Pipeline Cost

Effect of Changing Royalties

Changing royalties can play a major role in the economics!

Effect of Royalties on LNG NPW

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

0 100 200 300 400 500Flow rate (MMscfd)

NP

W (

MM

$) 10% Royalties

7% Royalties

5% Royalties

3% Royalties

Effects of Royalties on Pipeline NPW

-$5,000

-$4,000

-$3,000

-$2,000

-$1,000

$0

$1,000

$2,000

$3,000

$4,000

0 100 200 300 400 500

Flow rate (MMscfd)

NP

W (

MM

$) 10% Royalties

7% Royalties

5% Royalties

3% Royalties

Future Gas Cost

Based on Commercial Consumer U.S. Prices (1980-Present)

Found % changeUsed change and the random function in

Excel

Economic Comparison

• The most profitable option is to transport the natural gas by LNG

Vertical Wells (883000 ft3/d)

Net Present Worth (MM$) LNG Pipeline

130 $3,109 -$4,437

195 $5,063 -$3,399

260 $7,040 -$2,294

390$10,89

8 $545

 

Return On Investment    

130 20.54% 1.90%

195 22.26% 5.60%

260 22.93% 9.77%

390 23.86% 18.76%

Horizontal Wells (2.6 x 106 ft3/d)

Net Present Worth (MM$) LNG Pipeline

130 $5,126 -$1,220

195 $7,951 $1,310

260$10,89

4 $3,985

390$16,67

3 $9,963

 

Return On Investment    

130 35.89% 7.92%

195 39.84% 17.02%

260 41.35% 21.83%

390 44.05% 29.80%

Another Option

Total GTL Costs

0

1000

2000

3000

4000

5000

130 195 260 390

Gas Flow Rate (MMscfd)

Cos

t (M

M$)

Drilling

Surface Equipment

GTL Facility

Shipping

GTL Economics

Return On Investment

(MM$) 20 years 30 years

130 22.70% 23.35%

195 23.28% 23.93%

260 23.25% 23.90%

390 23.54% 24.20%

Net Present Worth (MM$) 20 years 30 years

130 $3,097 $4,011

195 $4,802 $6,183

260 $6,428 $8,276

390 $9,799 $12,580

Conclusion

It is the most economical to pursue transport by LNG, but if horizontal wells were drilled instead, there are many other options that would make good investments.

GTL production is also a possible option!The research that is on going in industry is

promising and we are getting close to producing natural gas hydrates.

Questions?