day 1 pm - technical evidence & ormen lange

KEY FUNDAMENTALS / ORMEN LANGE GAS FIELD

DAY 1 AFTERNOON

Key Reserve/Resource Evaluation Fundamentals

RESERVE EVALUATION FUNDAMENTALS

• Assessment of Reservoir Tank Unit

− Quality, Integrity, Entirety

• Key Elements of Technical Evidence

− Tank Integrity; Column Height; Formation Properties; Hydrocarbon Properties; Drainage Area; Economical Producibility; Recovery Factor; Well Operation Conditions/Facilities

• Key Commercial Evidence

− License to Operate; Commitment to Develop; Exporting & Sales; Royalty/PSA

Key Fundamentals & Ormen Lange Gas Field 3


• Key Elements of Technical Evidence

− Reservoir Tank Unit

− Hydrocarbon Column

− Reservoir/Formation Properties

− Fluid Properties (Hydrocarbons & Non-Hydrocarbons)

− Effective Drainage Area

− Economic Producibility

− Recovery Factor

− Wells, Facilities and Operation Conditions



• Key Elements of Commercial Evidence

− Mineral Right and Acreage/Block Entitlement » Effective period of acreage/block

» Exploration/development expiry date

− Commitment to Development (intent to develop) » Long term planning and budgeting

» Financial memorandum

− Exporting and Market Conditions » Sales contract

» Facility and exporting agreement

− Production Sharing Agreement » Partnership contract & Royalty terms



• Reservoir Tank Unit

− A group of vertically and areally connected porous rocks containing hydrocarbons & possibly water in communication

• Reservoir Field (consisting of one or more reservoir units)

− An area consisting a single or multiple reservoir units/blocks, which are grouped on or related to the same individual geological structural feature and/or stratigraphic condition. A field may have two or more reservoirs which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or by both.

− Reservoirs associated by being in overlapping or adjacent fields may be treated as a single or common operational field.

− The“structural” and “stratigraphical” terms are used to identify localized geological features, not the broader terms of basins, trends, provinces, plays, areas-of-interests, etc.



• Analog Assessments (based on reservoir units/fields)

− Analog Reservoir Unit

» A contiguous reservoir unit with relevant analog properties

− Local Analog

» A nearby non-contiguous reservoir unit with relevant analog properties

− Regional Analog

» A reservoir within the same basin with relevant analog properties

− Global Analog

» A reservoir in any location that has relevant analog properties

• Reservoir tank unit definition depends on appropriate engineering and geoscience evidence that the reservoir volume contains hydrocarbons which share common physical controls on distribution, contacts and saturation.



• The understanding required to define each Reservoir Unit or Block is coupled with the understanding and definition of the reservoir tank, hydrocarbon column, fluid contacts, dynamic data and other evidence which supports an evaluation of reservoir continuity, and is in practice worked in parallel with the assessment of evidence in each of the key technical areas.

• The evidence supporting the definition of each Reservoir Tank in a Reservoir Field may vary within that particular Field.

• Onshore, a Reservoir Tank Unit or a Reservoir Block is also phrased as a Reservoir Pool, implicitly suggesting reservoir communications



• Consideration of faults in the Reservoir Tank Unit

− Determination of whether faulting creates one or more reservoir units is based on an integral assessment of the available data.

− If no direct sand-to-sand contact across the fault, usually consider two reservoir units

− If there is sand-to-sand contact across the fault, exercise the following criteria to demonstrate whether communication exists:

» The degree of offset of the Reservoir Unit across the fault

» Structural studies that confirm the fault model

» Fault sealing studies benchmarked against analogs

» Evidence from analogs of either production continuity across faults or sealing faults

» Presence or absence of differences in initial pressure data (hydrostatic and hydrodynamic plotting) and fluid properties

» Field production history



• Reservoir Tank Unit

− A reservoir unit gross rock volume is estimated following the definition of the tank size through the use of seismic imaging and geologic modeling with or without well control.

− A well defined unambiguous seismic interpretation (dependent upon horizontal interpretation and depth conversion) of the reservoir unit should be consistent with the geological modeling.

− Definition of the structural crest is particularly important in determining the extent of the Hydrocarbon Column. Assessment of oil and gas volumes is not limited by the highest known hydrocarbon contact, but can be extended to the structural crest.

− Key definition of spill point, crest, closure, play type, trap types, leads to the confidence level of interpreting the quality, integrity and entirety of the Reservoir Tank Unit



• Hydrocarbon Column

− Hydrocarbon column extent is quantified by independent assessment of the gas water contact (GWC), oil water contact (OWC), and gas oil contact (GOC) if present, and structural crest.

− Direct evidence of a contact, either GOC, GWC, OWC, is part of well control with open-hole logs across the contact.

− Core and coring data may also be used as direct evidence, if core samples are taken from across the contact.

− Capillary pressure data may be used as indirect evidence of indicating a potential contact.

− Indirect definition of a contact may use a combination of pressure gradient data (RFT or WFT), PVT measurements, and direct hydrocarbon indication from seismic.

− WFT/DST samples may not serve as good evidence of the contact



• Hydrocarbon Column

− When no direct or indirect evidence of a contact is available, the Highest Known Hydrocarbon (HKH) and Lowest Known Hydrocarbon (LKH) determined from well control data within the same reservoir unit can be used.

− Gas column may be assumed to extend to the structural crest within the reservoir unit (this limits volume definition to the highest known gas unnecessary).

− Field production data, if available, can be used as part of an integrated analysis to support interpret hydrocarbon contacts

− When indirect evidence is presented, always state the uncertainty range of the contact



• Use of WFT Pressure Gradients − WFT pressure gradients to determine fluid contacts or free water levels (FWL) is

widely accepted in the industry and in most cases will form the basis of the definition of the Hydrocarbon Column where wells are typically drilled away from contacts.

− The result of using WFT pressure gradient data for determining fluid contacts or free water levels must be unambiguous and be applicable to the Reservoir Unit/Block, where the data were acquired and analyzed.

− The use of regional aquifer pressure gradient may only be used or determining fluid contact levels or free water levels where overwhelming evidence, from multiple penetrations of the aquifer, from water chemistry, indicates a consistent pressure interpretation within the basin.

− US SEC reserve estimation procedures do NOT accept this indirect evidence of fluid contacts or free water levels, unless the data and the interpretation is overwhelmingly evident.



• Use of Fluid PVT data

− In saturated oil reservoirs, the gas-oil-contact (GOC) can be determined from unambiguous interpretation of multiple PVT samples gathered from the oil leg within the Reservoir Unit/Block.

− The use of reservoir fluid samples from different Reservoir Units/Blocks may be used if there is full and convincing similarity between the fluids and pressures.

− Fluid samples collected from openhole wireline formation tester tools, drillstem testing, production flow test, surface separator/tanker, can be used to support the Reservoir Unit/Block and Hydrocarbon Column definitions, provided that they are not badly contaminated and representative.

− Advanced fluid property analysis, such as gas chromatography, gas fingertyping, fluid source studies, can be used to support the Reservoir Unit/Block and Hydrocarbon Column definitions.



• Reservoir/Formation Properties

− Within each Reservoir Tank Unit, the Reservoir Properties most important in the estimation of reserve/resources are:

» Net-to-gross pay ratio

» Porosity

» Hydrocarbon saturation

» Formation volume factor

» Rock and fluid compressibility

» Effective permeability/relative permeability

» Natural fracture development, density, distribution, orientation, if any

− These values are determined at well locations through core, log and formation test.



• Reservoir Formation Properties − Estimation of the Reservoir/Formation Properties away from wells will be

achieved through mapping based on a geological model, or in cases where the quality is sufficient, through direct seismic indication.

− Improvements in properties away from wells may be supported by unambiguous seismic and consistent geological model.

− The relative confidence in the mapping depends on:

» The number of wells that calibrate the interpretation through core and logs

» Whether the Reservoir/Formation Properties improve away from wells

» Availability of a consistent geological model

» Confidence in the ability to directly image the reservoir parameter

» A convincing body of evidence based on a broad dataset including analogs

− When field/reservoir production data becomes available, it can be used as part of an integrated analysis to support the definition of Reservoir/Formation Properties.



• Reservoir Fluids

− PVT analysis is necessary with high quality fluid samples acquired by either wireline formation testing, production test, drill-stem test, or any other industry recognized formation test that takes bottomhole formation fluid samples.

− These samples should come from the Reservoir Unit/Block or Reservoir Tank, nearby, adjacent, or any other analogous Reservoir Unit or Field.

− When Reservoir fluids have become well understood in a basin and an extensive dataset is available, analysis of a bottomhole or recombined surface sample (tanker or separator or Tutweiller) from a local analog can be considered.

− Reservoir fluids should be updated from field production data as part of an integrated interpretation.

− Reservoir fluid samples are routinely acquired by wireline formation testing and practices



• Effective/Defined Drainage

− The effective/defined drainage area is the portion of the Reservoir Unit that can be shown to have characteristics that will make it economically developable.

− This area usually means the one all in pressure communication (without separated compartments) with the planned development wells under economical producible conditions.

− The effective drainage is often related to recovery factor as factors related to reservoir/formation properties may not allow one well or more wells to effective drain hydrocarbons to the wellbore and be lifted to the wellhead.

− The drainage area should be justified by reservoir continuity within the Reservoir Unit, & is established from available engineering, geological and geophysical evidence.

− The drainage area can be further supported by production continuity.



Resources (Oil in Place or Gas in Place)

all connected hydrocarbon volumes contained in this reservoir (rock permeability,

naturally fracture connectivity, fluid properties, energy level, affect how much

hydrocarbon could flow to the well and be produced)

Reserves (commercially recoverable)

The volume that can be “seen” and

produced by this well economically

x Recovery Factor

Effective/Drainage Area



• Reservoir Effective Drainage and Continuity − In Reservoir Units containing wells, the defined drainage area may be extended

by reservoir continuity to the edge of the region of unambiguous seismic data within the Reservoir Unit that is contiguous to the well in the absence of any conflicting information.

− Alternatively the defined drainage area may be based upon the area around an existing well that is equivalent to the area defined by one offset well where the offset well spacing is either determined from the legal well spacing defined by the local regulatory authority or estimated from an unambiguous well test in the penetration or in a similar well tested in an analogous reservoir unit.

− Defined drainage area may include the area between two wells that are further than one offset well apart, if the regional reservoir continuity is demonstrated by unambiguous core and log correlation to be significantly greater than the distance between the two wells.

− Defined drainage area must not extend part the hydrocarbon column or outside of the reservoir unit



• Practically, effective or defined drainage area is estimated by

• Designed well test, or

• Accepted legal well spacing unit

• In North America (US and Canada)

• Development spacing unit (DSU), 640 acres, or 741 acres (300 ha)

• Outside North America

• Designed well test for boundary detection

• Reservoir continuity and compartmentalization

• Radius of investigation, as a function of flow rate, flow time, pressure transient drawdown, reservoir permeability and other parameters

tC

ktR

t

inv

44



• Economical Producibility − Evidence must exist to support the economical producibility of any volume of

reservoir unit in order to be considered for development

− The ability to produce from the reservoir unit at rates that support a valid economical case for the proposed overall full-cycle development

− Typical sources of evidence to support economical producibility are:

» A production test of sufficient length in the reservoir unit to establish

• Productivity of the well (IP rates under certain drawdown pressures)

• Drainage area per well and sustainable well rates used in the depletion plan

» A production test of sufficient length in an analog reservoir unit. Well logs and core analysis can be used for classifying volumes when the reservoir units can be shown to be analogous to other reservoirs where production has been established

» Wireline formation testing and measurements together with core, logs and seismic data in the reservoir unit, supported by productivity data from local analogs.



• Economical Producibility

− When a vertical test in a reservoir unit or analogous reservoir unit is used to represent planned horizontal wells, an equivalent horizontal well productivity should be calculated based on the flow test results to assess economical producibility.

− In remote areas, with few field under development, there might be no analogs that would be capable of providing sufficient certainty to approve volumes for development without a well production test to support this item.

− Dynamic data obtained when the reservoir unit is on production overrides the above test data in the assessment of economical producibility.



• Reservoir Recovery Factor (RF)

− The ratio of reservoir fluid volumes to be extracted under economical/operation conditions to the total fluid volumes contained in the reservoir unit/block/tank

− The only correct recovery factor comes from after a reservoir unit or block or tank or field is completely developed

− Confidence fro the expected recovery factor comes from reservoir performance prediction in integrating reservoir studies with an extensive industry wide analog database of regional and global recovery factors.

− Common practice for evaluating reservoir recovery factor estimates:

» Analogy

» Correlations

» Core analysis (SCAL)

» Numerical simulation sensitivity studies

» Gas material balance



• Reservoir Recovery Factor Evidence: − Natural depletion uses simply the energy contained within the reservoir tank to

produce the fluids, including fluid expansion, aquifer influx or reservoir compaction. RFs from primary depletion are estimated from fluid/core analysis and by material balance/numerical simulation.

− Assisted depletion that extends the natural depletion by water or gas injection to supplement aquifer/flooding or gas cap expansion for the purpose of maintaining reservoir energy and the initial phase conditions. RFs are supported by fluid and core analysis and can be estimated using analytical and material balance studies or numerical simulation.

− Secondary recovery schemes as a result of water/gas injection to improve pressure enhancement and sweep efficiency, can be supported by fluid and core analysis and estimated by analytical and numerical simulation studies.

− EOR schemes (miscible, gas cycling, thermal, chemical) involves special knowledge.



• Reservoir Recovery Factor

− Confidence is increased when secondary or enhanced recovery schemes are further supported by either performance data from the reservoir unit, a pilot or local analog.

− Recovery factor can be increased through time when supported by an integrated analysis of field production performance.

− For example, some stratigraphical traps or pools may have increased recovery factors, where seismic imaging and petrophysical studies may not reveal the entirety of the net pay.



• Wells, Facilities and Operation Conditions − Facilities, well life, and operating parameters should be consistent with proved,

probable and possible reserve and resources.

− Engineering design and operability studies for wells and facilities such as debottlenecking, reliability and facility optimization

− Well surveillance (SCADA), well management and intervention programs

− Regular assessment of operating efficiency and availability

− Benchmarking analogs

− Operational track record

− Demonstrable links between reservoir, wells, facilities, pipelines in depletion plans

− Regular reviews of operating and capital investments to maintain consistency with life of field and operability requirements or assumptions



• Wells, Facilities and Operation Conditions − Operating conditions always change as a field matures. The impact of these

changes on operating parameters and system availability should be assessed

− Benefits of modifications or reconfiguration for future conditions should be included in the reserve/resource estimations

− Planned cost should include well maintenance, mechanical sidetracks and extra well works, to main well stock and optimize recovery. When costs changes, well life should be re-assessed and production estimates should be made consistent with the occurring conditions with time.

− Facility design life is normally specified and supported by engineering studies. The facility life should be consistent with the economical recovery profile.



• Calculation of the Economic Limit:

− operating expenses / net income

− Example:

» Gas price: $6 / mscf HH

» Royalty tax: 15%

» Other taxes: 20%

» Forecast op-cost: $1.5 / mscf (variable) and $1000/month

» Economic Limit

= $1000 / (($6 – $1.5)*(1-0.2)*(1-0.15)) = 327 mcf/month

= 11 msc/day



t

Operational Limit

Economical Limit

q

qab

qab

t

Variable pricing forecast

Fixed pricing forecast

q

qab

Operational Limit: well unable to operate

due to mechanical/production/reservoir

issues (water-cut, liquid loading)

Economical Limit: well unable to operate

economically (oil/gas sales unable to break

even)

Variable Pricing Forecast: economical rate

up and down, but generally up (more

realistic but hard to forecast)

Fixed Pricing Forecast: using year-end

price to forecast the lifecycle of well

(unrealistic, but easy to practice)


Ormen Lange Gas Field, Norway

ORMEN LANGE GAS FIELD

Ormen Lange is the largest natural gas field under development in Norwegian continental shelf, 100 km NW of Kristiansund where seabed depths vary between 800 and 1,100 m. The reservoir is approximately 40 km long and 8 km wide and lies about 3,000 m below sea surface. Proved gas reserves reach 397 billion m³ (14 tcf).

Extreme natural conditions at the site (sub-zero temperatures most of the year, stormy seas, strong underwater currents, uneven seabed) put great demands on the technology used in the project.

Total cost is estimated to reach 66 billion Norwegian kroner by the time of completion, equivalent to about 10 billion US$.

The Ormen Lange field will be developed without using conventional offshore platforms. Instead, wellheads on the ocean floor is connected directly by pipes to an onshore processing facility at Nyhamna and the gas will be exported via 1,200 km Langeled pipeline to Easington in England. Production should start in October 2007. The field should produce 70 million m³ of natural gas per day.


ORMEN LANGE GAS FIELD The current ownership of Ormen Lange field:

Petoro AS: 36%

Norsk Hydro: 18%

Royal Dutch Shell: 17%

Statoil: 11%

DONG Energy: 10%

Exxon Mobil: 7%

Ormen Lange is operated by Norsk Hydro during the development stage. After 2007, Royal Dutch Shell becomes the operator.


Class Exercise & Brain Teasing

day 1 pm - technical evidence & ormen lange

Documents

communication reservoir

reservoir volume

noncontiguous reservoir

multiple reservoir unitsblocks

common operational field

geoscience evidence

fluid contacts

stratigraphical terms