Maximum Wellhead Operating Pressure

Well integrity is concerning about the well components such as X-tree, tubing, casing and all accessories inside the well like packers.
A major component Well Integrity issue will be the annular pressure limits to make sure our operating condition still below the safety limits. In order to determine what these limits are, the Maximum Allowable Wellhead Operating Pressure (MAWOP) must be calculated for each well.

The MAWOP will be the measure of how much pressure can be safely applied to an annulus according to the API Recommended Practice 90.

If two or more weights or grades are used in a string, the minimum weight or grade should be used in the MAWOP calculation.

We can use the following definitions when determining the MAWOP for each annulus:

"A" Annulus - The annulus designation between the production tubing and the production casing
"B" Annulus - The annulus designation between the production casing and the next outer casing. The letter designation continues in sequence for each and every outer annular space encountered between casing strings up to and including the surface casing and conductor casing.

How to Calculate MAWOP according to API RP90:

The MAWOP for annulus being evaluated is the lesser of the following:
· 50 percent of the minimum Internal Yield Pressure of the pipe body for the casing or production riser stated or
· 80 percent of the minimum Internal Yield Pressure of the pipe body of the next outer casing or production
· 75 percent of the minimum Collapse Pressure of the inner tubular pipe body

For the last casing or production riser string in the well, the MAWOP is the lesser of the following:
· 30 percent of the minimum Internal Yield Pressure of the pipe body for the casing or production riser stated; or 75 percent of the minimum Collapse Pressure of the inner tubular pipe body

About Chokes in Oil and Gas wells

A well is normally producing the fluid with a choke at the surface to control the flow rate. Most flowing wells have surface chokes for the following reasons:
· to reduce the pressure and improve safety
· to maintain a fixed allowable production limit
· to adjust the desired rate to the optimum as it is match with the well’s productivity and the predicted production plan
· to match the surface pressure of a well into a multi-well gathering line and to prevent back flow
There are several different types of chokes currently in use. They may be divided into two broad categories: variable or adjustable chokes and positive or fixed orifice.
Positive chokes have a fixed orifice dimension which may be replaceable and is usually of the bean type. The flow path is normally symmetric and circular. Fixed orifice chokes are commonly used when the flow rate is expected to remain steady over an extended time.

Normal beans are 6 inches long and are drilled in fractional increments of th-inch up to -inch. Smaller bean inserts, known as X-type, are used to provide closer control. Ceramic, tungsten carbide, and stainless steel beans are used where sand or corrosive fluids are produced. Changing the size of a fixed orifice choke normally requires shutting off flow, removing and replacing the bean. Some continuously variable or adjustable chokes operate similarly to a needle valve and allow the orifice size to be varied through a range from no flow to flow through a full opening.

Controlling the flow is obtained by turning the hand wheel which opens or closes the valve. Graduated stem markings indicate the equivalent diameter of the valve opening. Another type uses two circular discs, each of which has a pair of orifices. One disc is fixed while the other can be rotated so as to expose the desired flow area or block the flow altogether.

It is important in the design of the surface control system to understand the pressure versus flow rate performance of the choke at critical flow rates.
We can use some software like WellFlo, Reo, and Gap to modelling the choke performace.
In my experience it is important to consider the compositional properties of fluid when designing the choke type. I have ever done to do choke replacement due to leaking that caused by the abrasive fluid.

Designing ESP (Electrical Submergesible Pump) Oil well

· Determine the desired production rate (q)
· From this rate (q) calculate the bottom hole flowing pressure (Pwf) using productivity index (J) equation you are using commonly we use this equation: Pwf = (J * Pr – q)/J.
· Look at the list of your available pump you have in the stock that match with design rate
· Calculate the average specific gravity of liquid you have using this equation: SG fluid = Wc * SGw + (1 - Wc) SGo
· Calculate the pressure gradient along the tubing in the well with this : Gradien = SG fluid x 0.433
· Calculate the applied intake pump pressure using : PIP = Pwf - Gradien(Depth@pwf – Depth @ pumpsetting) note: the depth must in TVD
· Calculate the TDH (total dynamic head) that is Head due to tubing or WHP pressure + Net vertical lift + Friction lost or for quick calculation based on my experience is : TDH = ( WHP (psia) / 2.31 ) + ( Pump setting depth - (PIP/2.31) ) + 250 ( I normally used for friction loss)
· Calculate the required stages of the pump: Stages = ( TDH / (Head/Stages) using pump chart )
· Calculate the HP of the pump : HP = Q.TDH.SG/(135770.eff)
· Choose the proper motor type for this pimp

Water Injection Performace

Water Injection Performance Calculation


This is a brief summary to calculate or estimate the injection well performance. Injection well is the well that will have fluid flow from the surface into the reservoir. Injection well is the reverse condition of production well that flows from the reservoir to the surface. The injection well performance calculation then also will use the productivity index of production well but it will means that pressure gradient is in opposite direction.

Productivity index of the production well:
Productivity Index =


J =

J is in stock tank barrels per day per psi of drawdown.
The productivity index represents the dynamic response of the reservoir and its fluid properties within the drainage area of a specific well. It defines the relationship that exists between flow rate, q, and bottomhole flowing pressure, pwf, for a given average reservoir pressure, R. The productivity index is constant when flow parameters like permeability are constant. When bottomhole flowing pressure is above the bubble point the productivity index will be constant. As the pressure drops below the bubble point, however, the productivity index will decrease as gas comes out of solution, changes permeability values, and inhibits flow.

For injection well, it becomes:
Injectivity Index = Jin =





From this equation we can develop the injection flow performance (Pwf versus injection rate ) as you can see the curve below:














Usually we have to consider the formation fracture pressure so our fluid injections will not going to anywhere that could risk to the environment, and to make sure our fluid goes to our desired formation. Then you can put the line on the injection performance curve above where the pressure limitation of your injection to avoid formation fracturing.

Water Injection Performance Monitoring

Water injetion well Performance Monitoring


In my experience using Hall-Plot technique is the best for me to know the condition and the performance of water injection well. Pleas see the figure below
One comment from me is for the trend like on the D-positife skin/poor water quality can be also caused by the reservoir pressure increaseing or in other word the reservoir is over pressure condition. As you can imagine if the reservoir pressure increase due to some reason like (low reaservoir permeability or small reservoir tank capacity it will create back pressure to the bottom hole injection pressure, so then also impact to the surface injection pressure.

How to Increase Your Oil field Production

How to increase you oil field production
These steps are based on my experience and my thoughts that could increase your oil production from daily monitoring or well surveillance works,

1. We must know the productivity or IPR (inflow performance relationship) of all wells. Then try to model it the vertical lift performance and find out the operating rate the subjected well. If your operating point position on the IPR curve is at the left side of the IPR curve, then you have to think to increase this operating rate to move it at least to the middle of rate range on the IPR. This can be done by reducing the well head pressure or if it is already minimum or 100% opened you must consider other ways to create more drawdown in the bottom hole (installing bigger tubing size, ESP etc).


2. Review all the shut in wells in your field. And try to find the reason why it was shut in. Once you have known the problems, try to reactivate the well using new technology etc and also make the economical consideration and risk assement.


3. Check well performance if it is declining, try to find the answer why it is declining. If reservoir pressure issue, then we don’t have too many options to improve its performance. However, if you can find other reason likes skin or something that reducing the flow such as scale, sand problem or any solid doposit built up in welbore, we have to do something like pump clean up, wellbore clean up or matrix stimulation, sand controll installation etc. By knowing the problem it will make us easier to have better mitigation action plan.


4. Subsurface or GGRE review, need to review all the unopened pay zones behind casing of each wells either shut in or active wells. And also to consider secondary recovery technique to increase recovery factor or change out the artificial lift method with highr drawdown can be created than the exisisting one.


5. Create model of surface facility that is connected to the wells performance or it’s called well integrated production model to know and simulate the current operating system and find opportunities to do debottlenecking projects, Production optimization, etc.
   Hope those steps useful for you all.