Oil and Gas Exploration

Oil and Gas Exploration is the function of upstream tasked with finding economic accumulations of oil and gas.

E&P – The Search for Oil and Gas

The Oil and Gas Exploration Lesson consists of the following topics:

Learning Objectives
Obtain Access
The Lease
Government Take
Oil and Gas Agreement Variations
Fiscal Systems and Regimes Vary
Joint Operating Agreements (JOA’s)
Farmout Agreements
Exploration (Wildcat) Well
Seismic Interpretation
Well Evaluation
Evaluation: Open Hole Logging
Gross Pay – Net Pay
Open Hole Logging Results
Completing the Well
Appraisal Investment Decision
Reserves: The Petroleum System
Reserves: Conventional Exploration
Reserves: Unconventional Exploration
What are Reported Reserves – 1
What are Reported Reserves – 2
Evaluating Reserve Additions

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Obtaining Lease Access

To obtain rights and access to explore for and develop oil and gas resources in most countries, an E&P operator must commit to spending millions of dollars upfront, often including:

line-miles of new seismic surveys,
a number of drilled wells, and
front-end bonus payments.

No rational investor wants to make a large payment for a purchase whose quantity, quality, and longevity are largely unknown. However, that is essentially what is required of most E&P operators that seek to explore and develop in new (especially international) areas.

To balance the risk, there are three basic operating models that can apply to the exploration activity. An oil company or E&P operator can gain access to the resources:

On their own – by negotiating a specific agreement with the owner of the resources;
With a partner – using a Joint Operating Agreement (JOA)
As a project is underway – using a form of agreement called a Farmout.

The agreements for each of these operating models are now discussed in detail.

The Lease

In all countries except the US, the government owns the subsurface mineral resources. The forms of agreement to get access to these resources vary widely. In the US, the (mineral) lease form is a contract between the lessee and the lessor (the owner of the rights to the minerals).

The E&P operator’s Land Department acquires the rights to develop US properties from the mineral owners. The Exploration Department usually negotiates international lease obligations once a concession is won.

The lease grants the operator the right to explore and drill for, extract, remove, and dispose of any oil or gas that may be found on the leased land. A well cannot be drilled legally unless an operator is a mineral owner or has a valid lease.

Leases are valid as long as annual rental payments are made. If oil and gas are discovered a royalty is paid to the mineral owner. The lease can be extended for as long as oil or gas are produced.

Mineral leasing of public land is competitive. Additional discussion of leasing options and the bidding strategies used by E&P operators to obtain leases is in Lesson 5, Business Processes.

There are a number of regional authorities that manage mineral leasing for US public lands:

States administer any state trust lands.
The US Bureau of Land Management administers public lands, including National Forest lands.
The Bureau of Indian Affairs, administers Indian land, in cooperation with individual Indian Nations.

The Government Take

A strong, competitive world market exists in oil and gas concessions and contract rights, with over 120 host governments (federal, provincial, state) offering acreage and about 200 active IOC’s looking for opportunities. International host governments also try to achieve maximum benefit from any oil and gas activities, including:

training and technology transfer,
new jobs for both technical professionals and plant workers, and
development of local manufacturing and service capabilities to support projects.

More sophisticated E&P operators are incorporating the capabilities that the host governments are seeking in their new agreements.

However, the key benefit for most host governments is the stream of revenues that is associated with local production of oil and gas, called government take. Government take is really the “price” that E&P operators are willing to pay for exclusive access to concessions or contract rights for exploration and development.

This “price” depends on market forces:

Often the supply of concessions by host governments is limited, and
The demand for concessions by operators varies, depending on budgets and the crude oil price outlook.

Oil and Gas Agreement Variations

Host governments typically use three different types of oil and gas arrangements in working with operators.

Concessions usually have royalties and corporate income tax as their main components. However, other payments to the government may be applicable such as bonuses, rentals, special petroleum or windfall profit taxes, property taxes and export duties.

Under concessions, the operators are granted exclusive rights to exploration and production of the concession area and own all oil and gas production, subject only to the royalty. The royalty has to be provided in cash or kind to the government.

Production Sharing Contracts. Under PSC’s the NOC, or the host government directly, enters into a contract with the operator. Here, the operators finance and carry out all petroleum operations and receive an amount of oil or gas for the recovery of their costs and a share of the profits. Sometimes PSC’s also require other payments to the host government such as royalties, corporate income tax, windfall profit taxes, etc.

Risk Service Contracts. Under RSC’s, the E&P operators finance and carry out petroleum projects and receive a fee for this service which could be in cash or in kind. The fees typically permit the recovery of all or part of the operator’s costs and some type of profit component.

A subset of RSC’s is called a Technical Services Agreement (TSA’s). These are contracts where the IOC’s are paid to perform consulting services. E&P operators do not manage the projects and do not make any investments.

Note that the government take can be exactly the same under any of the three arrangements.

Financial Systems and Regimes Vary

Another term often used in host country arrangements is the fiscal system or regime. This term applies to all forms of payment to host governments in cash or in kind, such as bonuses, royalties, corporate income taxes, in-kind profit oil shares, windfall profit taxes, property taxes, and export duties.

It also includes any fees paid by the government to service contractors under one type of oil and gas arrangement. The chart shows that fiscal regimes can vary government take from 50% in the US GOM to over 90% in Libya.

Governments have considerable influence over when and how fast to extract petroleum resources. The fiscal system determines how risks and profits are shared between the government and the investor.

Host country resources can be extracted and converted into financial assets only once, and are eventually depleted. An important objective is to maximize the revenue to the government that can be effectively utilized in the long run. Achieving this objective depends on many factors, including:

the government’s ability to attract qualified investors,
the timing of production,
oil and gas price movements, and
the government’s capacity to spend revenue productively.

With high oil prices in 2005-2008, the industry saw increased resource nationalism; restricted access, “restructuring” of contract terms and tightening of fiscal terms by host governments. The rapid price decline in the latter half of 2008 could reverse some of these restrictive policies.

Joint Operating Agreements (JOA)

Another common form of agreement that often applies to US and international operations is a joint operating agreement, called JOA. In general, JOA’s, have four elements:

For operational practicality, an “Operator” is designated, who, at a minimum, will control day-to-day activities. The Operator’s powers, duties, compensation and replacement are specified.
The agreement sets out a method for the conduct of the joint operations, i.e., who has the authority to make what decisions, and under which circumstances.
The agreement contains the formulas for participation in costs, production and/or revenues, as well as ownership of property and materials.
If different companies own interests in different, segregated leases, the agreement will need to specify the formulas for pooling.

International JOA’s take into account the special concession or contracting arrangements involved in the host country. The international JOA is always subordinate to the host government contract, not vice versa.

Model form domestic and international JOA contracts have been developed by oil and gas industry associations.

Farmouts

Farmouts are a fundamental and essential vehicle for the exploration and development of oil and gas. Over the years they have evolved from short and simple letter agreements to voluminous documents.

Farmouts are agreements under which the owner of a working interest in a natural gas and oil lease assigns the working interest (or a portion of the working interest) to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.

The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

The expression “farmout“ is said to have originated in the US with Magnolia Petroleum Company in 1970.

In general, farmouts occur in the exploratory stage, when the commercial risks of the project failing to recover its costs are considerably greater to the operator than at the later development stages. Two examples are shown below;

“Farming out” would make sense if an operator is unable to develop expiring acreage due to budgetary constraints. The operator could also wish to reduce risk and would be willing to accept a lower return associated with a reduced acreage position.
“Farming in” makes sense if another operator’s budget can stand the costs of drilling. Thus the operator would be willing to accept greater costs (and risk) by increasing acreage position, and thus increase potential return.

Model form farmout contracts have been developed by the American Association of Petroleum Landmen.

Exploratory (Wildcat) Wells

An exploratory or wildcat well is one drilled in a previously unexplored area to test for commercial presence of hydrocarbons.

As the chart shows, the ideal well target is a pay zone, primarily areservoir trap. Migrating oil or gas is never commercial, it must be trapped in a productive reservoir. Think of migrating oil as a very large, wide river that is only 2-3 inches deep. The river must be trapped or dammed up to be useful for irrigation or power, and so must the oil and gas.

Drilling the exploratory well, also called a test well, is primarily a scientific enterprise:

The geologist examines well bore material to confirm the geologic profile.
The paleontologist examines the fossils, to establish the age of the rocks.
The geophysicist continually evaluates the physical downhole conditions.

Seismic Interpretation

Drilling a wildcat well has always been a risky proposition. Even drilling a well within a known field involves some level of uncertainty about what is below the surface.

Once the exploration basin and play has been identified, the next crucial step is selecting the location of the first well, recommended to exploration management by the geoscientists.

Advances in 2D and 3D seismic surveying and interpretation have helped refine the identification of likely hydrocarbon faults and traps, to the point where drilling risk has been reduced.

However, there can be more than one possible explanation for a seismic phenomenon, called a bright spot, which can suggest (but does not prove) the existence of subsurface hydrocarbons.

So the only answer is to drill the well. The uncertainty causes geologists to change the wildcat location numerous times as new data are analyzed

Well Evaluation

As the exploratory well is being drilled it is constantly evaluated to determine if there is enough oil and natural gas in the reservoir to make it commercial. Rock and fluid properties will determine how much oil and natural gas can be recovered from a reservoir.

There are three basic types of evaluation used:

Mud logging is the term for examining drill bit cuttings as the well is drilled.
Core samples allow the geologists to examine the actual physical rock or strata in its actual sequence and thickness.
Open hole logging, where an electric current is put into the ground. As the current passes through the various rock strata, the resistance differs for each sedimentary layer, and is recorded.

A well will either have hydrocarbons or it will not. These various evaluation tools tell much about the well being drilled, but more important is what they tell about the area or play being explored.

Open-hole logging data is primarily used to determine whether the wildcat well should be completed and turned into a productive location. A well with no commercial hydrocarbons is called a dry hole and is plugged and abandoned.

Evaluation: Mud Logging

Rock cuttings are generated as the bit works its way through the formation and are moved to the surface by the constantly circulating drilling mud.

At the surface, cuttings are removed by a piece of equipment called a shale shaker. Drill cuttings are sampled at regular intervals and keyed to the depth from which they came. These cuttings have important information about the borehole:

First, is the rate of penetration (ROP) of the drill bit. This information is continuously obtained by measuring the mud weight and viscosity, which is affected by changes in the types of cuttings in the drilling fluid.
Second, is the types of rocks that are being drilled (sandstone, limestone, shale, salt, etc) called the borehole lithology.
Third, any well bore gas captured in the mud stream is analyzed.
Finally, other hydrocarbon (oil) shows are discovered by exposing the cuttings to ultraviolet light.

This data is correlated to the depth of the borehole and produced in a chart, called a mud log, for analysis by the drilling engineers, geologists and geophysicists as drilling proceeds.

Evaluation: Core Samples

From time to time, drillers may use a special bit that drills out a long, solid 3-5 inch cylinder of rock instead of drilling cuttings. This 60-90 foot core section allows the geologists to examine the actual physical rock and sediment layers in proper sequence and thickness. Core analysis provides data regarding actual rock porosity, permeability, fluid content, depth and the geological age of the reservoir. A core sample is the only way to determine reservoir permeability.

The need for coring is carefully considered because it is a time consuming and expensive process. The industry does not have a continuous coring operation. Thus, drilling needs to be stopped until the core is cut and retrieved using a specialized hollow drill (called a core barrel) attached to the drill string.

The driller only wants to retrieve cores from formations that are suspected to contain commercial quantities of oil and gas.

Core samples are kept as long as the operator is active in a particular basin – in some cases decades.

Evaluation: Open Hole Logging

The physical evidence that the drilling mud brings up is important.

However, the most significant geological and geophysical data to establish whether the well is good comes from what are called open-hole logs, done at the bottom of the borehole. Open-hole logging equipment will not work if there is casing or pipe in the hole.

Electric log equipment used is usually a 80-140 foot piece of electronic equipment called a sonde (shown in the picture), which is lowered into the open section of the borehole – after the drill pipe is removed.

Gross Pay vs. Net Pay

To determine whether “A well is any good, and will make money“ four factors must be included in the economics:

Recoverable reserves
Field productivity
Oil and gas prices realized at the wellhead
Production costs, including any taxes or royalties

To establish recoverable reserves two important pieces of information are needed from the test well:

Gross pay is the term for the total thickness of the reservoir rock, including the impervious layers which do not contain hydrocarbons.

Net pay is the aggregate thickness of only those parts of the reservoir which contain and produce hydrocarbons, measured in feet of pay.

Open Hole Logging Results

To establish net pay, open hole or wireline logging is used.

A number of charts (similar to the picture) are then generated that show the varying electric resistance of the sedimentary layers and fluids surrounding the well – at two foot intervals. Here, an electric current is put into the ground, passes through the resistive strata and into the sonde.

In the chart, the yellow sections indicate the presence of hydrocarbons, in this case gas.

Three other types of information are obtained through electric logging methods:

rock type and porosity,
fluid content of the pores, and
the mechanical and fluid flow conditions of the well.

Completing the Well

If a wildcat well is considered to have commercial quantities it is called a discovery well.

Additional equipment is then brought to the wellsite to complete the well, and make it productive. A successful completion depends on making the optimum mechanical connection between the well bore and the reservoir.

Production tubing is run into the well bore. It is generally much smaller in diameter than the production casing. Unlike casing, the production tubing is not cemented into place. It hangs from the wellhead, as shown in the diagram.

Once productive, a key test, called a bottom hole pressure test, is conducted to measure the reservoir pressure of the well under flowing and shut-in conditions. This data is needed to establish parameters for the reservoir model to define the next series of appraisal wells, and the size and design of the production facilities.

Appraisal Investment Decision

A discovery well is very good news for exploration management, but the work and capital investment often then intensifies. The full extent of the field and productivity of the reservoir needs to be determined to make sure the economics of field development are still positive.

To establish the limits of the reservoir, it is necessary to drill more wells, called appraisal or delineation wells. It stands to reason that the probability of success declines as distance from the discovery well increases. Even with 3D seismic, reinforced with the new test well data, the clarity of the subsurface picture degrades with a greater distance from the discovery.

Selecting the next series of wells, often called step-out wells, is a period of high economic risk. Determining whether a field is commercial, especially offshore, requires a precise appraisal program of enough wells to establish both geological and commercial parameters. Additionally, the high cost of the production facilities (and offshore platforms) must now be brought into the economics.

The key for exploration management is to know when to bring the appraisal phase to an end, and:

either cut losses and abandon the project, or
proceed with development as quickly as possible to generate cash to pay off the high initial investment.

Reserves

The Petroleum System

The term petroleum system refers to the combination of the main geological factors which led to the accumulation of hydrocarbon reserves. As shown in the chart,

A porous and permeable reservoir rock is needed to contain the hydrocarbons and allow them to accumulate. Most reservoir rocks are composed of sandstone or limestone carbonates which have plenty of room inside to trap oil, like a sponge.
The reservoir must have an impermeable cap rock which acts as a barrier to the natural upward movement or migration of fluids.
The system must be sealed in a trap in order to permit the hydrocarbons to accumulate.

The first challenge for geologists is finding these traps, and the second is assessing the characteristics of the reservoir rock and thus the producibility of the oil. To form a productive reservoir, the succession of geological events, referred to as the timing, must also be favorable. For example, it is crucial that the trap is formed before the hydrocarbons migrate.

Also note in the chart that gas is lightest. Oil is more dense than gas. Salt water, always present in reservoirs, is the heaviest.

Beneath the earth’s surface, oil will ooze through rocks if there is enough pore space in them. It is important to remember that oil is not all by itself in some sort of underground cave, but is, instead, contained within solid rock – which has enough room within it to actually soak up oil.

Sedimentary rocks in the subsurface normally contain the oil and gas – being lighter than the surrounding water – exert an upward force that results in a movement known as migration.

The hydrocarbons’ migration upward will continue as long as the rock pores and fractures are sufficiently interconnected, a characteristic that geologists define as permeability. However, should they encounter rocks with low permeability, migration stops and the hydrocarbons become trapped.

Conventional Exploration

There are two fundamentally different types of hydrocarbon resources that affect the exploration approach and commercial development strategy, conventional and unconventional.

A conventional resource is found in those reservoirs where the oil and gas is recovered through vertical wellbores and typically requires minimal processing prior to sale. Most conventional hydrocarbon reservoirs have defined limits, with characteristics such as a hydrocarbon/water contact, traps and cap rock. This leads to discrete fields.

For conventional resources, the key economic driver is exploration well or wildcat success. A well is drilled, logged, and maybe cored, and well productivity is then fairly easy to establish. The major economic uncertainty is associated with the size of the overall reservoir.

Unconventional Exploration

Unconventional resources are controlled by wide regional geology, not local. This leads to accumulations that cover huge areas and have poorly defined limits. In unconventional, the word field is used more often to mean an administrative unit.

For unconventional resources such as shale oil, shale gas, oil sands, bitumen and coalbed methane, the priorities are reversed. Typically, you know where it is all located. The key to success is whether it can be produced.

Here, exploration is more like development and may require years of detailed geologic studies, great expense for numerous delineation wells, and long periods of testing called pilot projects.

Unconventional deposits require different and much more complex production methods. For example, unconventional oil may need additional upgrading to be usable as a refinery feedstock.

In summary, unconventional resources are more capital intensive (for development, production, and upgrading) than conventional ones. Future prospects for unconventional resources depend crude and gas price and the investment cost and technology needed to convert them into commercially usable reserves.

The total amount of unconventional oil and gas resources in the world considerably exceeds the amount of conventional reserves.

Reported Reserves

It is important to understand that there are two primary definitions of reserves, one for exploration-development and another for finance.

The term “reserves” used by exploration usually means the projected ultimate recovery of hydrocarbons from a given field, often called estimated ultimate recovery (EUR).
The term “reported reserves” has fiduciary implications to the CFO, banker or financial analyst. Terms are defined in rules by global reporting authorities, the US SEC as an example, to describe varying levels of confidence in the existence of the reserves. Reported reserves are volumes which are expected to be sold from assets by the application of a development project to drill and complete a well, similar to those shown in the chart.

What else is needed for reported reserves?

Reported reserves are the summation of future production from a given field on a date forward until the economic limit of production is reached, which is dependent on:

commodity price,
cost of production and
available technology.

Another important consideration, as indicated in the chart, is the contract which is applicable to the field, often called a lease offtake agreement. As examples:

In a joint project with a NOC, the E&P operator can only book the reserves for their entitlement under the contract with the NOC.
If a large gas field is in a stranded location, can be produced, but there is no contract for the large volumes of gas, they cannot be reported.

In summary, if the reserves cannot be economically produced, and a commercial agreement to offtake this production does not exist, they cannot be counted as recoverable.

Evaluating Reserve Additions

Once the appraisal process is completed, the discovered reserves are generally estimated as three probabilities, as shown in the chart:

Proved or Proven (P1 or P90) – This is the lowest reserve estimate figure, the amount that the geologists are 90% sure is there.
Probable or Proved+Probable (P2 or P50) – The average probability, the figure that is expected to be closest to the true reserves.
Possible or Proved+Probable+Possible (P3 or P10) – This is the highest figure, the amount that the geologists are 10% sure is there.

The best choice of estimate to use for budgeting purposes is P50, since a 50% estimate is just as likely to be higher than lower.

In order for volumes to move from one “P” category to the next, the technical issues which cause them to be placed in less certain categories must be resolved. This may include:

The drilling of additional wells,
The monitoring of current production to better understand reservoir performance, or
The implementation of a pilot project to have greater confidence in the volumes that full scale development projects may eventually produce.

Related Resources:

What is the difference between Upstream and Downstream?

Drilling Wells for Oil and Gas and Offshore Drilling

Oil 101

I would like to thank you for a brilliant interactive 101 materials. I did use to prepare for the recruitment process is Royal Dutch Shell, and I managed to take a new role in a new oil and gas industry.:)

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