Reserve Estimation

One of the main factors that determines the viability of an investment in an oil and gas field is the volume of the hydrocarbons present in it. In simple terms, we would like to invest to produce oil and gas, if only the money that can be generated by producing the hydrocarbon from that field generates profits. As typical investments in a field run into billions of dollars in terms of facilities and operation costs, it becomes imperative to have a good idea about the hydrocarbons present.

Initially, when we set out to develop a field, we do not have much idea about the reservoir and its characteristics viz. porosity, permeability, areal extent, thickness etc. As we continue to drill wells and develop the field, we get more and more data about the reservoir.

Correspondingly, at the beginning we have very little idea about the crude volume in place at the reservoir and so we employ some relatively simple and unsophisticated methods for determining the volume. These methods have a high degree of uncertainity associated with it. This means that there is a high probability that the volume which we have estimated from these methods may have a wide variance from the actual volume in the reservoir.  The methods employed at this stage are : Analogy and Volumetrics.

Later , as we have more data from the reservoir , we can employ more sophisticated and reliable methods for generating the volume of hydrocarbon. The results that we generate from these methods have a higher degree of certainity and we can expect the results to be closer to the actual values.The methods employed are : Decline Curve Analysis , Material Balance and Numerical Reservoir Simulation.

  

Decline Curve Analysis or DCA

As a reservoir is produced, after an initial peak and plateau period, the production rate starts to decline at certain rate. Analyzing this decline, a Reservoir Engineer can predict the Estimated Ultimate Recovery of the field. This technique is called DCA or Decline Curve Analysis.

While identifying the decline rate or decline trend, one needs to make sure the production is occurring at constant "operating conditions". For example, constant "bean size" in a producing well. 

The scope of analysis may be 

(a) an individual well or well-string

(b) a given reservoir zone

(c) a field 

(d) a bigger area or region

or even

(e) global

However, individual well-string or a given reservoir zone are commonly used or technically valid.

There are other kinds of 'trend analysis', e.g.

(a) Water-Oil-Ratio (WOR) vs. Cum Oil

(b) Gas-Oil-Ratio (GOR) vs. Cum. Oil

These are also used in conjunction with oil decline analysis to determine the economic life of the well or reservoir or the field in question.

For gas reservoir, a different approach, "p/Z-plot" is adopted. It will be discussed separately.

Decide your Reservoir Engineering tool wisely....

Providing timely and sound technical "advice" to the management is one of the primary jobs of a Reservoir Engineer. "Advice" is like a product that Reservoir Engineers generate to assist management take effective decisions. These decisions in turn effects the financial health of the company.

With the limited time and resources, it is very important to decide the correct tool to be used to generate the correct and timely "advice". In order to justify a bigger financial commitment by the investors, a more rigorous and robust technique is required. However, more the robust and rigorous technique is, more data / information is demanded by the technique. A simpler technique can be used to obtain results in shorter time using less amount of data; however, the results may not be as reliable as a more complex method would yield.

There is a time element to the equation. With longer investment of man-days, a better results might be obtained. However, capability of the technique; quality and quantity of data play a limiting role to the robustness of the result. 

Figure-1

Figure-1 attempts to typical time duration required to carry out different RE studies and a relative complexity of the result that can be achieved from these techniques. It compares (a) Decline Curve Analysis, (b) Material Balance, (c) Streamline Simulation, and (d) Finite Difference Simulation.

Reservoir Drive Mechanisms

Production of oil and gas from a hydrocarbon reservoir is simply a matter of supply of the energy that would allow the reservoir fluids to come up to the surface. Depending on some properties of reservoir viz. pressure , geology , PVT properties of the crude , each reservoir would have a different mechanism for energy supply.

The mechanisms for energy supply for production of oil and gas from the reservoir is what we commonly know as the Reservoir Drive Mechanism.

The most commonly observed Drive Mechanisms include :

• Solution Gas Drive
• Gas Cap Drive 
• Water Drive 
• Compaction Drive
• Gravity Drainage

More than one drive mechanism can exist in a reservoir. However , one  is usually the dominant mechanism in the reservoir .

If we have an idea about the dominant drive mechanism in a reservoir , we can generate the expected recovery , production and pressure profiles of the reservoir.

Hydrocarbon Reservoir Types

Hydrocarbon Reservoirs can be classified in terms of how the fluid present changes due to change in pressure and temperature as it is brought out to the surface. 

• Dry Gas Reservoir: The fluid present in the reservoir is in gaseous form and it remains in gaseous form as it is brought out to the surface.

• Retrograde-Condensate Gas Reservoir: The fluid present in the reservoir is in gaseous form. However, part of it condenses into liquid form either in the reservoir itself or on it's way to the surface. What is produced is primarily gas with smaller quantities of liquid hydrocarbon.

• Wet Gas Reservoir: The fluid present in the reservoir is primarily gas, but contains small amount of liquid. When produced, gas is produced along with small amount of liquid. 

• Volatile Oil Reservoir: The fluid present in the reservoir is very light oil. Gas forms as it is brought to the surface. If produced oil is kept in an open container, it evaporates away.

• Black Oil Reservoir: The fluid present in the reservoir is heavier oil. Some dissolved gas might be present. However, the produced oil is "dead", i.e., does not evaporates away if kept in an open container.

Sources:

• http://www.informit.com/articles/article.aspx?p=2241145&seqNum=4
• http://petrowiki.org/Natural_gas_properties

Gas Lift

As production from the reservoir continues,  gradually the energy of the reservoir depletes and it is no longer able to lift oil to the surface. At that point, Artificial Lift is employed which enables us to bring the oil from the depleted reservoir through the well to the surface. Approximately, 80% of the oil wells around the world are now on Artificial Lift and the most popular method employed is the Gas Lift.

In Gas Lift, a high pressure gas is injected into the well from the Casing - Tubing annulus. The injected gas reduces the  density of the fluid above the point of injection in the well. Because of the overall reduced density, the fluid exerts less pressure on the reservoir and flow from the reservoir into the well can continue.

Gas Lift System can broadly be classified into two main categories: 

• Continuous Gas Lift
• Intermittent Gas Lift

Continuous Gas Lift 

In this, gas is continuously injected into the well at the maximum possible depth, which depends on the injection pressure and the well depth. The  gas mixes with the produced well fluid and decreases its density and hence  the  pressure gradient of the mixture from the point of gas injection to the surface. The decreased  pressure gradient reduces the flowing Bottomhole Pressure (BHP) below the static BHP thereby creating a difference in pressure  that allows the reservoir fluid to flow into the wellbore. 

This is typically employed in wells with high production rate and high BHP.

Continuous Gas Lift

Intermittent Gas Lift

As the name suggests, gas is injected periodically into the wellbore which displaces the fluid which accumulates as a slug in the well. When the high pressure gas is injected into the well , it rapidly expands and this expansion pushes  the slug towards the surface. Because of the intermittent nature of the gas injection , the well produces less than a well with continuous gas lift. 

The intermittent gas-lift method typically is used on wells that have low production rates.

Intermittent Gas Lift

Thermal EOR

Thermal recovery techniques principally targets crude oil with very high density  ( < 20 deg API ) which cannot flow on its own. These methods raise the temperature of the reservoir which in turn reduces the viscosity of the crude and breaks the larger crude oil molecules into smaller molecules. The heat also reduces the surface tension and improves the overall mobility of the crude.

Some of the major techniques that are employed in the industry :

• Cyclic Steam Stimulation
• Steam Flood
• In-Situ Combustion