How downhole monitoring impacts the efficiency of Gas Lift operations.
Critical Factors For Gas Lift Production
One of the critical factors in the application of production system analysis, also Nodal analysis, is downhole data. In existing conditions, static well tests, downhole gradient surveys, or production logging surveys deliver periodic data points. These regular surveys provide boundary conditions for the nodal analysis and are not accurate in assessing drifts and corrections for the dynamic changes. The dynamic movement of variables is best defined by curves of extrapolated numbers from periodic tests. The result? What is occurring in the reservoir might not be immediately noticeable from surface data production trends. Downhole monitoring systems help overcome such situations and give a dynamic high-resolution feed of downhole conditions.
The immediate and explicit advantages these systems have over old school conventional methods are:
- Delivery of highly accurate pressure data- It can deliver multi-point data in a single installed system. We can have actual reservoir pressure from below packer, along with tubing and annulus pressure, temperature (and vibration if required, although not very useful in Gas lift design) near each Gas lift valve. This allows monitoring of the reservoir pressure while also measuring injection pressures allowing optimization opportunities.
- The operator can continuously optimize a normally operating gas-lift system by properly allocating injected gas to react to events such as a change in gas-lift supply volume, change in manifold pressure, or water cuts.
Downhole Pressure is a critical component for reservoir characterization, simulation and modelling. It is equally vital in everyday Production operations, providing us better insight into the dynamic behaviour of reservoir and Wellbore. It also helps determine J profile, correlating pressure values with IPR performance, artificial lift monitoring, optimization, and diagnostics, maximizing daily production EUR & reducing CAPEX & OPEX. We will analyze the importance of Downhole pressure- Reservoir/Annular and Wellbore/Tubing, which a Downhole monitoring system provides, thus establishing the system’s value and necessity.
Radial Flow Equation
It is not unknown to any E&P operator the critical importance of the flow model and analysis of fluid flow in multi phases through the reservoir. We take an example of a basic radial flow equation based on Darcy’s law to analyze the variables required to generate a fluid flow model.
Q = k*h* (Pe–Pwf) / (141.2*u*Bo*ln(re/rw))
- Q = Well inflow capability in Stock tank Barrels oil/day
- k = permeability in millidarcy
- h = net pay of reservoir in feet
- Pe = initial reservoir pressure in psi
- Pwf = Bottom hole flowing pressure in psi
- 2 = constant for this equation to provide a solution in STB/d
- u = oil viscosity in centipoise
- Bo = Oil formation volume factor in Reservoir Bbls/Stock Tank Bbls
- ln = natural log function
- re = drainage radius in feet
As seen in the above equation, flow is described as a function of Pressure Drawdown and other downhole reservoir parameters. We can combine all the controllable variables and rewrite the equation to highlight the critical dynamic variables.
Radial Flow Equation
(Reduced to controllable variables – Pressure)
Q = C*(Pe–Pwf) / D
- Q = well inflow capability in Stock tank Barrels oil/day
- C = k * h in millidarcy-m
- Pe = initial reservoir pressure in psi
- Pwf = Bottom hole flowing pressure in psi (this is what we want to understand)
The remaining critical variables are now Pressure in Pe and Pwf.
Inflow Performance Relationship (IPR)
To calculate an Inflow Performance Relationship (IPR) curve, we require:
- Static Reservoir Pressure at time of calculation – Pe
- Bottom hole flowing pressure at the time of calculation – Pwf
- Oil Production test rate that corresponds to Bottom hole flowing
Bottom hole flowing pressure (pump intake pressure) determined in several ways:
- Estimated by simply guessing – not accurate
- Estimated by correlations and calculations using fluid level estimates and surface pressures – more accurate
Bottom Hole Flowing Pressure found in the area indicated by ‘Perforation Zone’.
Advantage of Downhole Monitoring Over Other Methods
Bottom hole flowing pressure references the pressure in the Wellbore inside the production casing directly across the midpoint of the perforations. It is often used interchangeably with Pump intake pressure but is only interchangeable with accuracy if the pump is landed at or very close to perforations. It is one of the critical variables needed to determine IPR. More importantly, it’s the dynamic value that is important to understand the reservoir & flow model.
We will highlight the difference between two main methods widely accepted in the Industry to determine Bottom hole flowing pressure and see their shortcomings and advantages, respectively:
Shortcomings/Disadvantages Of Surface Fluid Level Measurement
Advantages Of Continuous Downhole Pressure Monitoring
Indirect measurement using calculations and correlations
Direct measurement at the sand face or near the gas lift valve
It is widely used in the Industry and is an accepted methodology to estimate Bottom hole flowing pressure where direct measurement is not available
Most accurate determination of Realtime Bottom hole flowing pressure
A common issue in the measurement of Bottom hole flowing pressure & Temperature using this method is Erratic readings, leading to:
- Erratic fluid level determination
- Erratic estimate of fluid density (caused by flawed fluid analysis, gas entrapment, water entrainment in fluid – emulsions)
- Utilization of erratic correlations
- Having significant Total Vertical Distance (TVD) between pump intake and perforations
Provides many additional benefits at no incremental cost, a few are:
- Gathering build-up information for reservoir management and regulatory requirements (field pressure surveys)
- Determine if skin damage occurring across the sand face over time
- Predictive tool for proactive planning of Well maintenance (i.e. tubing change/choke size/valve size change determination)
It is only a point in time indication of Bottom hole flowing pressure – which makes it more challenging to maximize/optimize production
Real-time ability to continuously adjust Gas lift operating conditions to maximize/optimize Production.
Real-time measurements help in the reduction of rig time per intervention by helping most of the time with planned workovers and preemptive corrections before failure. This reduces OPEX substantially.
Real-time monitoring also helps in reducing safety risks and hazard probability by lowering exposure to Well intervention.
Errors have a cumulative effect on the error factor and can significantly impact estimating the Bottom hole flowing pressure. A 5% error in fluid level and fluid density = 10% +/- error in estimated Pwf. It would not be surprising to see errors in the range of 10% or greater (ie 5 % low on fluid level estimate, 5 % low on fluid density = .95 x .95 = ~90% of correct Pwf). 5% the other way = 110% of correct Pwf.
Use of Downhole Gauge Values - Pe & Pwf To Maximize Production
Below is a graphical representation with representational numbers highlighting the quantitative difference that can be created by knowing Real-Time Pwf :
The graph represents a Test Well’s IPR curve with 165 Bbls/d of Test rate and reservoir pressure of 3300 psi;
The operator has Assumed or calculated from the surface and static periodic measurements a Bottom hole flowing pressure of 1500 psi. The plot is showing less potential to add incremental Production as reservoir pressure gets closer to zero.
Figure 1: Inflow Performance Relationship Graph
Tubing Performance Curves are primarily impacted by:
- Fluid Composition (i.e. Water cut, GOR, fluid viscosity)
- Surface pressures
In the given scenario, we can achieve an increase in production by:
- Increasing Drawdown on Well – Reduce Bottom hole flowing pressure- Pwf to 1000 psi from 1500 psi
- Change in tubing size
- Reducing surface pressure
- Optimize A/L- Valve, choke size etc.
Please refer to the graphical representation with the tubing performance curve overlapped on the IPR curve, which showcases the potential gap in the efficiency of the production rate.
Figure 2: Inflow Performance Relationship vs. Opportunity Graph
Example of increasing from 165 bbls/d to 195 bbls/d provides 30 bbls/d incremental – at $70/bbls WTI oil price = ~USD $7,66,500/year in additional revenue potential.
Suppose we have a Well candidate with a similar production rate and taking a highly conservative estimate of 25% effectiveness of the given conditions. In that case, it still amounts to almost USD $1,90,000 in additional revenue potential.
And most importantly, the given condition, which is possible due to the accurately known value of Pwf, can be achieved by a simple reduction of Bottom Hole Flowing Pressure.
- Increasing tubing size reduces friction losses in tubular, resulting in lower Bottom hole flowing pressure and increased Production.
- Reducing surface flowline pressure directly results in a reduction in Bottom hole flowing pressure and increased Production.
This sums up one of our company’s prominent slogans:
“You can’t manage what you don’t measure”
Use of Downhole Gauge Values - Pe & Pwf To Reduce Operating Costs
In gas lift operations, the operator maximizes Production by monitoring tubing intake pressures. The motive is to determine the effect of increasing additional gas injection rate, which leads to a decrease in Bottom hole flowing pressure, ceases to exist. With Pe and Pwf values, and correlation of the impact of injection rate on Bottom hole flowing Pressure and Maximum allowable surface pressure, one can make specific changes to reduce injection gas costs:
- Prevents waste of injection rate and pressure that may be detrimental to total Well Production
- Reduces wasted energy from over-injecting gas
- It provides the most appropriate calculations to optimize injection volume & rate and maintain maximum drawdown on well, leading to efficient optimization of surface facilities
- It helps in determining if the Well has become tubing capacity limited and may not be Well deliverability limited
- Utilizes capacity in compressor that could be used to produce additional oil across the field – impacts overall field production and sales revenue – can be100’s of Thousands to Millions of dollars/yr in lost revenue depending on the scale of operation.
- Determine at what point additional gas injection rate increases cause maximum pressure ratings (maximum injection pressure) to be reached. This may occur before reaching a tubing capacity constraint which would require an upsizing of the gas lift injection valves/ports
If you refer to the below representational graph, it helps correlate the Downhole Pressure values with the surface injection pressure. The objective is always to maximize Production by reducing the Bottom hole flowing Pressure Pwf as low as possible given the Completion configuration in the Wellbore.
Knowing Realtime Bottom hole flowing pressure indicates Well performance relative to potential based on the IPR curve. Therefore, we are continuously updating on what opportunity exists to increase Production or reduce Operating Costs. It also helps in Well designs on future drills for more optimally sized production casing/tubing configurations.
Figure 3: Impact of Gas Injection Rate on bottom Hole Flowing Pressure & Surface Injection Pressure
Below are few calculated examples of Cost reduction based on the application of the above-given model:
For 1000 HP compressor and 10% wasted HP at a cost of $0.10/KW*h = $0.10 x 1000 x 0.746 x 10% x 24 = $179/d or ~$65,000/yr
(HP x 0.746 = KW. Multiply Price/KW*h x HP x 0.746 x % wasted HP x 24 hours/d = Cost of wasted HP on a daily basis.)
For 1000 HP compressor and 10% wasted HP at a cost of $2.00/GJ = $2.00 x 1000 x 0.746 x 10% x 86.4×10^-3 GJ/d= ~$13/d or ~$4,700/yr
(1 KW = 1KJ/s = 86.4×10^-3 GJ/d. Multiply Price/GJ x HP x 0.746 x % wasted HP x 86.4×10^-3 GJ/d = Cost of wasted HP on a daily basis.
If Compressor capacity is 20 mmscf/d and 60% is being utilized for gas lift (i.e. 12 mmscf/d), of which 1.2 mmscf/d is over injected (10%) due to no optimization, then the oil production is being impacted by this wasted compression capacity used for gas lift.
If the field producing GOR is, say, 5000 SCF/Bbls, then the amount of deferred oil production is:
1.2 mmscf/d / 5000 scf/Bbls = 240 Bbls/d
240 Bbls/d @$70/Bbls = $14,400/d or ~$5.25MM/yr in deferred revenue.
If we take a highly conservative ratio, even a reduction as little as 5 BBls/d @$70/Bbls equates to savings of more than US$127,000/yr.