1. Schlumberger Artificial Lift Engineering
GAS LIFT APPLICATION FOR HEAVY CRUDE WITH EMULSION Dacion Field, Venezuela
Harryson Huang
Schlumberger Artificial Lift Engineering
Venezuela
Topics:
1. Dacion well completion, fluid and reservoir characteristics
2. Gas lift design for heavy crude with emulsion
3. Lesson learned
The presentation will cover four topics: introduction to Dacion field characteristics, gas lift design techniques and considerations for heavy crude with emulsion, matching FGS techniques in building representative well model, and lesson learned by ALE team in Dacion.

2. DACION FIELD - VENEZUELA
Fluid and Reservoir Characteristic:
More than 500 sandstone reservoir layers. Strong water drive
Reservoir depth = ± 4000 ft TVD (upper sands), ± 6000 ft TVD (lower sands)
Sand thickness = ft TVD
Reservoir pressure = ± 1600 psia (upper sands), ± 2500 psia (lower sands)
Reservoir temperature = ± 160 oF (upper sands), ± 200 oF (lower sands)
Ke = mD (mostly 2500 mD)
GOR = scf/bbl (mostly 200)
API gravity = deg (mostly deg)
Emulsion, asphaltene, paraffin
Sand (common). Scale (carbonate, barium. Minor)
Production rate bfpd
Dacion field in Venezuela has so many reservoir layers that are normally categorized into the upper sands (the A’s, normally less water), the middle sands (L’s, M’s, N’s, O’s, P’s, R’s), and the lower sands (S’, T’s, U’s, normally more water). Permeability is normally high, API gravity and GOR are low. The reservoirs / sands are normally not consolidated. Almost no wells can flow naturally since the beginning. As the WC rises, almost all wells are producing with emulsion. Some wells have carbonate or barium scale problem.

3. Completion:
Multi zone, single selective gravel pack completion (most common)
3-1/2” in tubing (most common)
Gas lift system (90% of the lift system)
Multizone, single selective gravel pack completion (Dowell ISO-AllPack) is normally used due to unconsolidated sands. Tubing size of 3-1/2” is normally used for 7” casing (new wells).
Additional information:
There are 2 slim hole wells completed with conventional GL mandrels (5-1/2” casing, 2-3/8” tubing) flowing through casing annulus. We are looking for SPM for this application.

4. GAS LIFT DESIGN FOR HEAVY CRUDE WITH EMULSION
1. Effective for gravity above 16 degrees API
2. Full design, no generic design
3. Normal GL design procedure applied:
Use reservoir inflow model to determine PI
Casing pressure drop use “Ptmin-Ptmax method”
Use design bias according to engineer’s degree of confidence
4. Use oil viscosity & emulsion viscosity correction
5. Select multiphase flow correlation from offset wells
Gas lift application in wells with many different oil API gravity’ has showed that GL is effective for crude from 16 degrees API and above. Due to many different reservoir layers and fluid characteristics, a full design is always needed, a generic design won’t work. Designing gas lift for heavy crude is not different with general gas lift design, the same procedure applied (building good inflow model, use casing pressure drop and design bias, etc). Only that more fluid data is needed especially oil and emulsion mixture viscosity. We have also learned that for some reservoir layers, especially the middle sands, Beggs & Brill correlation works better than Hagedorn & Brown, which generally works well for the field.

5. Gas Lift Design Flexibility
1. Anticipate higher water cut / emulsion
2. Anticipate reservoir pressure / PI decline
3. Anticipate demulsifier chemical injection
4. Anticipate temperature rise
5. Design for more prolific zone, anticipate other zone(s) characteristics.
It is important to have a flexible gas lift design that will work on many different circumstances:
- Related to reservoir: higher water cut, higher emulsion viscosity, reservoir pressure or PI decline, and the temperature change as the result of those changes.
- Related to people: application of demulsifier chemical injection, and decision to change producing zone in order to get higher oil rate.

6. Important Fluid Properties
The important fluid properties are the oil viscosity and emulsion mixture viscosity. In Dacion, we have taken several samples across the field and measured the oil viscosity at atmospheric pressure at 4 different temperatures. That is how the API gravity vs Viscosity plots was generated.
For emulsion mixture viscosity, it differs according to WC. If non-emulsion mixture viscosity is going down with increasing WC, emulsion mixture viscosity is going up with increasing WC till it hits the inversion point, when the emulsion basically breaks out leaving oil and water as separate phases. A set of empirical multipliers can used to calculate emulsion mixture viscosity from non-emulsion mixture viscosity.

7. Gas Lift Design Example
Here is an example of how a flexible design looks like:
Using well model we predicted that mandrel #3 and #4 would be needed as lifting point some time in the future when WC rised, therefore we used valve with bigger port size there. In this example mandrel #4 would be used as lifting point when WC increased to 40%. The TRO’s were carefully calculated to ensure the valves open when needed. 2 mandrels below the orifice were set to anticipate declining inflow performance.
Alternative lifting points
Assigned lifting point

8. Gas Lift Design Example, Cont’
KO Pressure
OP Pressure
The design worked well as showed by FGS. With some little adjustment, we matched the FGS to get better well model.
Well model matched with actual flowing gradient

9. Gas Lift Historical Performance
Low Pressure Gas Lift (850 psig):
PI < 7 , Average drawdown* = 400 psi
PI > 7 , Average drawdown* = 90 psi
PI = , WC = 65 %  Lifting depth ft
High Pressure Gas Lift (1250 psig):
PI < 7 , Average drawdown* = 500 psi
PI > 7 , Average drawdown* = 125 psi
PI = , WC = 65 %  Lifting depth ft
*from 112 QLBU data
We have 2 GL systems in the field: low pressure gas lift (850 psig at wellhead) and high pressure gas lift (1250 psig at wellhead). Actually we are in the process of migrating into one system HPGL. The presentation shows the average pressure drawdown and depth of lifting point for each system.

10. Effectiveness of Gas Lift GL vs ESP
To show the effectiveness of gas lift for heavy crude, we can compare the production performance of GL to ESP. We have 4 wells converted from GL to ESP due to high inflow performance. Here we’ll show 2 of them. The incremental production rate is quite good, but not far exceeding that of GL.
There are 3 steps of production increase on LM-225 well:
First, when we applied demulsifier chemical injection.
Second, when we converted the well from LPGL to HPGL system.
Third, when we converted the well from HPGL to ESP.

11. Effectiveness of Gas Lift GL vs ESP, Cont’
No Demulsifier
Demulsifier
Here is the second example. ESP production is not much exceeding that of GL.
There are 2 steps of production increase on LG-324 well:
First, when we applied demulsifier chemical injection. It had been on HPGL since the beginning.
Second, when we converted the well from HPGL to ESP.

12. Optimum Production Rate at Different WC without Emulsion Effect
Here we want to show the effect of emulsion to gas lift design. If emulsion is not present, the deepest points of injection at various WC will be very close to each other. Therefore one lifting point selected above the cluster will serve as stable lifting point for the rest of the well life (if we consider WC is the only parameter changing over time). Assuming inflow performance remains the same, production rate will decline slowly as WC rises.

13. Optimum Production Rate at Different WC with Emulsion Effect
If emulsion is present, the deepest points of injection at various WC will be more spreaded. It is difficult to select one stable lifting point that can give optimum result at various WC. Therefore several alternative lifting points can be prepared to deal with changing WC over time. Assuming inflow performance remains the same, production rate will decline sharply as WC rises till it hits the emulsion inversion point and kicks back up again.

14. Actual Data
Here is the actual example of the production rate around inversion point. As the WC rose hitting the inversion point, production rate suddenly jumped up.

15. Lesson Learned
Together with the whole Dacion team, we have brought Dacion production from 8,500 bopd on January 1998 to 42,000 bopd on December Here are some lesson learned from that process:
Converting LPGL to HPGL system has given good result as showed here. Average gain from the conversion is 40-50%. Therefore the decision has been made to convert the whole field into HPGL system.
Not only that HPGL improves production rate, it also improve well stability. With HPGL it is easier to reach closer to critical flow regime across the orifice.

16. HPGL Conversion Case: GG-210
Lesson Learned, Cont’
HPGL Conversion Case: GG-210
Study:
Matched current rate: 1133 BFPD
Estimated rate with HPGL: 1541 BFPD
Actual Result:
June 30, 2000 (LPGL): 909 BFPD
August 1, 2000 (HPGL): 1531 BFPD
Note:
LPGL: 850 psig system
HPGL: psig system
This is an example how we convert a well from LPGL to HPGL system. Only slickline intervention was needed here, i.e. to change several valves and move the orifice to deeper mandrel.
First we got FGS and test data. Then we built the well model. Then we used the well model to predict the condition when HPGL was applied. Based on that, we redesigned the gas lift configuration and predicted the new production rate. After the GLVCO was performed, we got another test data and compared it to our prediction. It was very close. So, we know that the new design works well.

17. Benefit of Demulsifier Chemical
Lesson Learned, Cont’
Benefit of Demulsifier Chemical
Another important lesson learned in the use of demulsifier chemical injection. The result has varied from well to well: some have reacted strongly, some have not. The example here is the one reacted strongly to the chemical. As the injection pump was turned off, production rate fell down. As the injection pump was turned back on, production rate came up again. Some wells are equipped with capillary line that is used to inject the chemical down to bottom. On wells without capillary line, the chemical is injected with the GL gas. There isn’t formal conclusion about the benefit of capillary line in comparison to injecting with the gas. A further study is needed.

18. Lesson Learned, Cont’ Temperature lock problem
Accurate temperature profile prediction. Anticipate WC rise.
Multi-point injection problem
More conservative approach in design.
Controlled well unloading rate 100 psi / 10 minutes.
Valve change out
Prepare different type of latches in stock (eq. Camco M latches).
Displace tubing volume with diesel before GLV CO.
Use neoprene packing element with brass backup rings.
Deviation
Use orienting style mandrel for deviation above 15 degree.
From day-to-day gas lift operation, here are some more lesson learned:
- Temperature lock. The valves cannot open to pass gas when needed because the predicted temperature is lower than the actual. Therefore we have learned how to get accurate temperature profile.
- Multi-point injection problem. Some valves are opened when not needed. It is due to TRO set too low (expected temperature is too high). Or because the orifice is set too deep (expected rate is lower). Another reason is washed-out valves. Therefore, unloading rate should be slow.
- Valves change out operation should be as short as possible: smooth operation with no valve mis-set or dropped, no problem in pulling and setting valve. This can be achieved by: having better designed latch (such as Camco M latch) available just in case needed when the normal latch (Camco BK-2) fails to set, displacing tubing volume with diesel before the operation to ensure clean fluid inside the tubing and no sand or heavy sludge that can disturb the operation, and using neoprene packing element with brass backup rings to avoid packing from swelling.
- If the well deviation is more than 15 deg, orienting style mandrels should be used. We had several problems setting valves into non-orienting style mandrels at deviation around 18 degrees.

19. Q & A
Full field modeling is not in place yet, however we have done well by well gas lift injection rate optimization using multirate testing as our primary data and Wellflo as our secondary.