Separator Test

Separator Tests are conducted to determine the changes in the volumetric behavior of the reservoir fluid as it passes through the separators and then into the stock tank. The resulting volumetric behavior is influenced to a large extent by the operating conditions, i.e., pressure and temperature of the surface separation facilities.

Objectives

• To provide the essential laboratory information for determining the optimum surface conditions, which in turn will maximize the Stock-Tank oil production.
• To obtain the PVT parameters (Bo, Rs and Bt) in combination with the DL test.

The SEP tests are performed only on the original oil at Pb.

The Test

• Place a HC sample at Pb and Tres. Let the vol be `V_(sat)`.
• Sample is displaced and flashed through laboratory multistage separator system
• Commonly 1 to 3 stages
• The P & T are set to represent actual durface facilities
• Gas liberated in each stage is removed and sp gr & vol at std condition meadured.
• The vol of remaining oil in  the last stage is (representaing stock -tank condition) is measured and recorded as `(V_(o))_(st)`
• The experimentally measured data are used to calculate FVF & Rs:
• Oil FVF @ `P_(b)` as measured by flash lib., `B_(ofb)=V_(sat)/(V_(o))_(st)` [bbl/STB]
• Solution GOR`P_(b)` as measured by flash lib, `R_(s fb) = (V_(g))_(sc)/(V_(o))_(st)` [scf/STB]
• `(V_(g))_(sc)` = total volume of gas removed from separators, [scf]

Determination of the optimum separator pressure

The above lab procedure is repeated at a series of different sep. P and at a fixed Temp.

• Recommended for at least four tests.
• The optimum set of Pressures is the one that gives the minumum oil FVF, `B_(ofb)`

At the same time, 

• Stock-tank Oil gravity must be maximum
• Total gas removed, `(V_(g))_(sc)` must be mnimum.

Notes:

By definition, Oil FVF (Bo) is the volume of oil at the reservoir pressure and temperature divided by the resulting stock-tank oil volume after it passes through the surface separations. Hence, its value is very much dependent on the surface operations. 

The Differential Liberation (DL) test is considered as a multiple series of flashes at the elevated reservoir temperature, whereas Separator Test (SEP) is a one or two-stage flash experiment at low pressure and low temperature as expected in actual field surface facilities.

Adjustment of `B_(o)` and `R_(s)` from Separator Test

Amyx et al. (1960) and Dake (1978) adjustment of `B_(o)` and `R_(s)`

Amyx et al. (1960) and Dake (1978) proposed a procedure for constructing the oil formation volume factor and gas solubility curves by using the DL test data in conjunction with the experimental SEP (flash) test data for a given set of separator conditions:

Step 1: Calculate the differential shrinkage factor `S_(od)` (bbl/bbl) at various pressures by

`S_(od) = B_(od)/B_(odb)`
where,
`B_(od)` = Differential relative oil volume factor at pressure p, bbl/STB
`B_(odb)` = Differential relative oil volume factor at `P_(b)`, bbl/STB

* `S_(od)` will be 1 (one) at `P_(b)` and less than one at p < `P_(b)`

Step 2: Adjust the relative volume data

`B_(o) = B_(ofb) * S_(od)`
where, `B_(o)` = Oil FVF bbl/STB
`B_(ofd)` = Oil FVF at `P_(b)` as obtained from SEP (flash) test = `V_(sat)/(V_(o))_(st)`

Step 3: Calculate Oil FVF above `P_(b)` by

`B_(o) = V_(rel) / B_(ofb)`
where,
`V_(rel)` = relative oil volume as generated CCE test.

Step 4: Adjust the differential gas solubility data `R_(sd)` to give the required gas solubility factor `R_(s)`

`R_(s) = R_(s fb) - (R_(sdb)-R_(sd))*B_(ofb)/B_(obd)`
`R_(s)` = gas solubility, scf/STB
`R_(s fb)` = bubble-point solution gas-oil-ration from SEP test , scrf/STB
`R_(sdb)` = solution gas-oil-ratio at bubble point pressure as measured by the DL test, scf/STB
`R_(sd)` = solution gas-oil-ratio at various pressure levels as measured by the DL test, scf/STB

Notes

These adjustments will typically,

• Lower Bo (FVF) as Rs as compared to the DL test data
• May produce Bo < 1.0 and Rs < 0. These needed to be manually corrected as Bo=1 and Rs=0.

Step 5: Calculate the two phase (total) FVF, `B_(t)` by

`B_(t) = B_(ofb)/V_(rel)`
where,
`V_(rel)` = Relative oil volume below `P_(b)`
Similar values can be obtained from DL test by
`B_(t) = B_(td) * B_(ofb)/B_(odb)`
where, `B_(td)` = relative total volume

Reservoir Simulators Comparison

Simulator	Developer	Finite Element	Streamline	BlackOil	Compositional	Chemical EOR	Geo-mechanics	Thermal
E100	Schlumberger	Yes	No	Yes	No	No	No	No
E300	Schlumberger	Yes	No	No	Yes	No	No	No
INTERSECT	Schlumberger	Yes	No	Yes	Yes	No	?	?
tNavigator	RFD	Yes	No	No	Yes	No	No	No
Nexus	Landmark Graphics / Halliburton	Yes	No	Yes	No	No	No	No
UTCHEM	U. of Austin	Yes	No	Yes	No	Yes	No	No
MoRes	Shell	Yes	No	Yes	No	No	No	No
EMPOWER	ExxonMobil	Yes	No	Yes	No	No	No	No
STARS	CGM	Yes	No	Yes	No	No	No	No
IMAX	CGM	Yes	No	Yes	No	No	No	No
GEM	CGM	Yes	No	Yes	No	No	No	No
REVEAL	Petroleum Experts	Yes	No	Yes	No	No	No	No

ASP Flooding - Various Lab Tests Required

Polymer
- Aqueous stability test
- Filtration test
- Viscosity @ various shear rate

Surfactant
- Salinity scan test
- IFT (may be Solubility Test) - done with O/W=1:1 ratio
- Oil Scan Test ( IFT test donet at different O/W ratio)

Core Flood Test
- To see if significant oil recovery could be achieved.
- To see the reaction of rock mineralogy with the proposed chemical slug.

ASP Flooding - Reservoir Selection Criteria

A] Formation / Rock Mineralogy Sandstone Reservoirs are preferred and "Anionic Surfactant" can be used. In Carbonate Reservoirs, "Anionic Surfactant" are highly absorbed, hence cannot be used. On the other hand, "Cationic Surfactant", which might be used in Carbonate reservoirs are expensive and economically not viable. Moreover, there is also a rock of Anhydrite formation in such reservoirs. Clay also absorbs surfactant. If the reservoir has high clay contents, it might not be suitable for ASP flooding. 

B] Oil Composition and Acid Number/Acidity These are important specially for alkali & surfactant. The Acid Number of Crude should be high (min. 0.3mg KOH/g of oil or higher) so that Alkali reacts with it and produce enough soap. 

C] Oil Viscosity This is particularly important for polymer component of the flooding. It determines the required Mobility Control and hence the design Polymer concentration, slug size etc. Usually crude oil of lower viscosity of 35cP or less is preferred. 

D] The Reservoir Temperature is expected to be less than 90 C, and preferably between 40-50C. Higher temperature degrades polymer and impacts the optimal salinity of surfactant.

E] Formation Permeability is expected to be high from 500mD to Darcies for easy movement of high molecular weight chemicals, especially polymers.

ASP Flooding

ASP flooding is a Chemical Enhanced Oil Recovery method where Alkali, Surfactant and Polymers are injected either in a given sequence or all together. The three chemicals have different effects. Often they interact with reservoir fluids (oil & water), rock minerals and among themselves to enhance oil recovery. In this article, we will explore these effects.

Effects of Alkali:
Alkali such as Caustic Soda (Na2CO3) are added to the chemical cocktail. It has two primary impact:
(a) Alkali reacts with the in-situ "Petro-Acids" and produces "Soap", a kind of surfactant. It compliments the surfactant requirement.
(b) Alkali competes for the absorption sites along with polymer and surfactant.
(c) Alkali causes 'emulsification' which improves sweep efficiency.
PLUS
(d) Oil Entrainment Effect
(e) Bubble Entrapment Effect
(f) Wettability Reserval

Effects of Surfactant:
Surfactant primarily works and IFT reducer. It loosen up the oil particles attached to the rock surfaces and thus assist move them closer to  the producing well. The effect is usually quantified using "Capillary Number", defined by:

          Nc = uμ / σ

where,
          u = displacing fluid velocity
          μ = displacing fluid viscosity
          σ = Inter-Facial Tension (IFT)

As Capillary No. increases, more oil droplets get detached from the rock surfaces and move towards the producers. In other words, it reduces the Irreducible Water Saturation (S_wirr).

Effects of Polymer:

• Polymer helps in improving the sweep efficiency of the injected chemical by mobility control.
• Due to "ViscoElastic" property, polymer flooding helps push/pull oil droplets from dead-end pores.
• Another, often ignored positive impact is the favorable economics compared to water injection. For the same effect, less amount of pore volume need to be injected.

The Synergies and Interactions of ASP:
When the three types of chemicals, namely Alkali, Surfactant and Polymer are injected "together", an increased oil recovery is observed. It is probably due to the advantage obtained due to the synergies and interactions between the said chemicals. These effects can be summarized as follows:
1. Alkali competes with absorption sites and hence reduces polymer and surfactant absorption, hence their requirements.
2. Alkali reacts with acidic crude oil and generate soap, called "petro-soap". This soap has low optimum salinity whereas injected synthetic surfactant has higher optimum salinity. As a result, the mixture of petro-soap and synthetic surfactant has a wider range of optimum salinity where IFT is low.
3. Emulsion improves sweep efficiency as the small bubble blocks the wider pore throats and forces the displacing fluid to enter the narrower pore throats. Petro-soap and surfactant make emulsion stable due to reduced IFT. Polymer may also help to stabilize emulsions owning to its high viscosity to reduced coalescence.
4. Addition of polymer improves sweep efficiency of the entire chemical slug, enabling more oil bearing zone exposed to surfactant and alkali.

Abbreviations

OAPL = Open Acreage License Policy HELP = Hydrocarbon Exploration and Licensing Policy NELP = New Exploration Licensing Policy NDR = National Data Repository

Black Oil vs Compositional Modeling

We often hear the Reservoir Engineers talking about Black-Oil model and Compositional Model. What are these? How do they compare? 

All these are different fluid model or the part of numerical simulation model that handles how the fluids, that is, oil, water, gas and any other substances would behave at different pressure and temperature.

Black Oil model is relatively simpler model with only three fluids - oil, water and gas. 

An extended version of Black-Oil model, called Extended Black Oil model takes are of volatile oil in gas and dissolved gas in oil.

A Compositional Model  on the other, tracks any number of components the fluid might actually has - like different hydrocarbons (C1, C2, C3, C4. C5, C6, C7,... etc), H2S, CO2, Water etc. These models are complex and takes lot more computing time than Black-Oil models.  

Brain Deposit !!

In the recent visit to the USA while addressing a large crowd of the Indian diaspora of the Silicon Valley, Indian Prime Minister Sri Narendra Modi mentioned an interesting term - "Brain Deposit". For him, the flow of talents from India to other countries is not "Brain Drain", rather "Brain Deposit", that he hopes that one day will return to "Mother India" with interest, i.e. with enhanced expertise. That`s what he calls "Brain Gain With Interest". According to him, that day is perhaps now or in the very near future.

Does it apply only to the IT sector or to our Oil&Gas sector as well? The Indian E&P companies including Oil India and ONGCL have experienced "Brain Drain" for quite a long time. These companies groomed talents in various fields like geosciences, reservoir engineering, production engineering, drilling etc from the very nascent stage. They hire fresh graduates, often with degrees with no direct relevance to the industry and spends time, money and man-hours to train them. After working and gaining experience for few years, many of them leave the company and the country in search of better opportunities. The time, money and man-hours spent apparently goes down the drain. The expertise and skills imparted by the Indian companies are utilized later by the foreign companies. Are these "Brain Drain"  or "Deposit" ?  

Volumetric Method of Reserves Estimation

The volumetric method of reservoir is a very simple and yet elegant mathematical tool that gives a fairly accurate idea about the volume of hydrocarbons in the reservoir. Its accuracy depends upon a correct estimation of certain physical properties of the reservoir viz. Porosity , Reservoir thickness .

In the simplest mathematical terms , the volume is determined as 

Where , V is the volume of the hydrocarbon in reservoir
              A is the area over which the reservoir is spread
              h is the thickness of the reservoir
              phi is the reservoir porosity
              Swc is the connate water saturation
              Bo is the formation volume factor

Gas Cap Blowdown (GCBD)

Gas Cap Blowdown (GCBD) is a process of depressurizing the gas cap of a reservoir.

GCBD is applied to extract the gas available in the gas cap of a reservoir after full extraction of the oil reserves. After the operator is convinced that the remaining oil volume can not be commercially extracted, the pressure energy preserved in the gas cap is no longer required. Hence, it can be allowed to deplete or depressurize and in the process gas can be produced for sales or other applications.

GCBD is carried out especially in oil-rim or oil-sheet type reservoirs where oil is sandwiched between an aquifer and a gas cap. It is carried out in several stages as described below.

Stage-I: Stop pressure maintenance, that is, shut-down any gas and water injection wells, while keep producing the oil producers as normal.

Stage-II: Open-up the high GOR wells previously shut-down. Keep producing oil and gas from other existing wells. GOR will increase in all the wells and eventually they will all become gas wells.

Stage-III: The down-dip wells will be watered-out. Shut-down any watered out wells. The water-front will gradually move up the reservoir watering out the gas wells one by one. At the end, the crestal most well.

The life-cycle of an oil rim under-going GCBD is shown in the following series of figures. Abbreviations: OP=Oil Producer, GI=Gas Injector, HGOR=High Gas Oil Ratio, GOR=Gas-Oil-Ratio, GP=Gas Producer.

Figure-1: At the beginning of field life. 

Figure-2: In later stage of field life. 

Figure-3: At the end of oil producing phase. Decision time for GCBD.

Figure-4: Stage-I of GCBD started.

Figure-5: Stage-II of GCBD started.

Figure-6: Stage-III of GCBD.

Figure-7: At the end of GCBD process.

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

Oil Companies

The oil companies or agencies involved in the oil industry can be broadly classified into 3 groups:

1. Host Authorities
2. Operating Company or Operators
3. Service Providers

What is Streamline Simulation?

Streamline simulation technique simplifies the conventional finite difference 3D simulation (FD) into a number of 1D problems by assuming some streamlines or pipes that transport the oil molecules from high pressure zone to low pressure zone. They depict the actual flow-path of fluid molecules within the reservoir.

Source: Schlumberger

Because of its simplicity, large reservoir model can be subjected to such simulation techniques with limited computer resources. Or, large number of models or realizations can be analyzed within short period of time. The technique may not give a robust result that can be fully trusted for large scale economic investment decisions. (We have to rely on more reliable and proven techniques of FD simulation). However, it is very good tool for a number of purposes.