Well Production Optimization: Going Back to Basics

The only way to get the optimum production from an oil or gas well is by tuning them to be at optimum operating conditions. This optimum condition should be attained regardless of the market situation, this is either at low or high oil/gas prices. It is a condition that leads to a sound financial situation for any company involved in the exploitation of hydrocarbons. 

Since the engineers concerned with the production optimization process are normally involved in multiple tasks within the team, or due to a high number of wells being under review, most of the time, the wells are not performing at its optimum conditions, which means, the company is losing production, this is, money. 

Following, some guidelines are leading to get the wells at optimum conditions. There are two topics to be touched on: the design stage, which is the phase where either the team is involved in the development phase of a new field/new well, or a well intervention is planned and the completion will be modified. The second topic is related to the optimization of artificial lift performance. Only the ESP and gas lift systems, as the major systems that are deployed by most of the companies, will be discussed.

Design Stage

One of the most common problems in gas wells is related to liquid loading. With this condition, the gas production is remarkably decreased due to the unwanted water, or the condensate fluid not being moved to the surface. Normally this condition is present when the reservoir pressure has dropped and so, the flowing bottom hole pressure is not enough to carry the liquid to the surface. To properly manage this condition, it is necessary to predict such pressure at which the liquid loading will be a problem. One option then is to predict the abandonment pressure, assuming the well will be abandoned when the serious slugging condition will be present. Figure 1 shows the well model for this example case. As seen, there is a reservoir pressure condition (900 psi) which will lead to the slugging condition. There are two options that could be considered, to defer the liquid loading to the lowest possible abandonment pressure, while maximizing the rate of hydrocarbons recovery. One is the use of a velocity string, which should be properly designed for this purpose. This option implies a well intervention with a rig. The other option is the use of a jet pump on the surface, which allows decreasing the line pressure, and so, getting an additional hydrocarbon recovery at this lower wellhead pressure. The advantage of this option is that no well intervention is required. 

For an oil well, the operating window, for specific conditions like tubing string, flowing bottom hole pressure, completion type, among others, should be defined before the well starts producing, and thus, the flowing pressure and rate are characterized and used to compare against real well performance. In this way, any remarkable discrepancy is identified and an action plan is prepared. As seen in Figure 2, limiting points like the maximum flowing wellhead pressure (Pwh) at which the well can sustain flow (minimum stable rate), and the minimum Pwh required to produce the maximum rate (target rate), are identified. A valid test rate (point red in the inflow curve) is required to validate the inflow model. In this way, those parameters should be used to keep the well producing at its optimum condition. It should be mentioned that this model should be frequently updated with well tests or additional information like GOR or flowing gradient data.

One of the properties that are remarkably changing in the well is the GOR, which is taken from the PVT analysis, but generally from samples analyzed early in the field development stage. One way to operationally determine this parameter is by having a well test, adding a gauge at a defined depth. Having the rate, and using the tubing performance curves, the actual GOR is defined by matching the data with available curves, as it is depicted in Figure 3.  This matched GOR is used to update the well model.

The default Hagedorn/Brown correlation, which defines the pressure drop along with the tubing (outflow performance) in an oil-producing well, should be validated by having a well test and a gradient survey from the surface to the bottom of the well, as shown in Figure 4. With this pressure survey, the correlation is tuned and the well model should be updated with this matched correlation.

The skin is a design element in the connection formation-wellbore couple, named completion. The system model, inflow, and outflow performance curves define the expected rates at different conditions of both the inflow and outflow sides. In the particular case of the validation of the Hagedorn/Brown correlation mentioned before, the discrepancy between the default correlation and the matched correlation is reflected in the skin value for each specific case. Figure 5 shows the rate target for the cases of default and corrected correlation, as a result of having different skin values. The default correlation shows a skin value of around 13, while the validated correlation has a skin of around 7.7. The expected rates are accordingly calculated, which shows an exceptional oil rate difference. And this discrepancy is due to having a properly calibrated correlation, which is normally taken as default by most of the engineers in charge of creating the system model for oil wells.

One of the most common completion types for oil and gas wells is perforating. Normally the decision to use the type of guns to be deployed in a well is decided on the availability of the guns. It is quite common in certain areas to find that the service providers only have one type of gun, so the companies are constrained to go for this option. In order to evaluate the performance of two different gun systems, a system model should be prepared, like the one depicted in Figure 6. In this plot, the evaluation is performed using the Tubing Conveyed Perforating (TCP) and the Through Tubing Perforating guns. The main difference between those guns is the way they are conveyed to the target depth, as well as the energy released by each one. Having the same possible pre-perforating conditions for both systems, we see that there is a substantial difference in the expected rate performance. The difference again is caused by the skin associated with each particular case.

Now, comparing the same type of gun, but with different shot density and explosive amounts, we may find results like the one shown in Figure 7. In this case, the difference in the Skin value reflected in the expected rate is a result of the length of penetration reached by each type of gun.

When dealing with two types of completions deploying perforating systems: perforating completions and gravel pack completions, it is important to understand the role of parameters associated with each one of them, in order to optimize the skin to be obtained by each one of those systems. As seen in Table I, having a perforating completion, the parameter that will render the optimum skin, and so the optimum rate, is the perforating length. In contrast, when the perforations are part of a gravel pack completion, in this case, the most important parameter is the perforation diameter, which will facilitate the pass of the gravel pack material, as can be seen in Table 2. 

Artificial Lift Performance

One of the most important features related to an ESP system, currently available, is the Real-Time Data display. The high-frequency and high-resolution pressure and liquid rate data acquisition allow the production optimization and improvement, as well as the optimization of other crucial conditions like ESP system Run Life, Power Consumption, and ESP system Uptime. 

Small changes in the Frequency and the Wellhead pressure lead to accountable changes in the liquid rate being handled by the pump. As it can be seen in Figure 8, a change in 5 Hz in the Frequency, allows the dispersion of the liquid rate values, and so, acting as a multi-rate test, the ESP Pressure Intake and the Liquid Rate can be plotted, in order to establish a status pressure, for the current conditions of the well. Benefits like efficient drawdown management, the definition of the proper pump sizing, and the update of reservoir current potential are of outstanding benefit, which are parameters that drive the optimum well performance in terms of productivity.

Of particular benefit is the determination of the Skin of the well, by plotting the apparent skin vs rate allowing to determine the rate-dependent skin (Y-intercept). With this technique, future impacts of the well rates can be predicted. This analysis can determine the changes over time in the PI and the depletion performance. 

The gas lift is a very grateful system as the well will be producing even with a poor design. Many companies make the initial design for the gas lift, keeping it for years, just based on the fact that they still get some production. There are different techniques to improve the performance of the wells under this type of artificial lit. One way is based on the gas injected versus fluid production. A Well Performance Index is calculated using the gas injected vs the produced fluids. With this index, the poor performer wells are identified and ranked, building in this way a pool of candidate wells for optimization purposes. The surface restrictions can also be identified by a Target Injection Index, (Ratio: Casing pressure and Wellhead Pressure/Casing Pressure). 

A plot is also a useful tool to identify those poor performance wells, as seen in Figure 9. A linear relationship is established between the gas injection and liquid production. Wells with lower injection rates and lower liquid production are identified. Additionally, a predicted performance area is defined as the extrapolated linear tendency for the field. In this way, target rates are forecasted corresponding to the cases where higher injection rates would be available. An action plan then is implemented with the poor candidate wells and the wells to be positioned in the Predicted Performance region, and the modifications leading to minimize/eliminate the surface restrictions.

Before each well is intervened, the model for the gas injection should be prepared, based on the updated reservoir, wellbore, and wellhead conditions. Figure 10 shows the gas injection regions versus oil production rates, depending on the available gas injection rates. As can be observed, there is a region with gas injection rates that will render optimum oil rates. There is also a zone where the gas injection will perform under unstable conditions, and there is a theoretical optimum gas injection rate.

This plot represents the expected operating conditions for each well. With this information, the subsurface gas lift design is originated, as depicted in Figure 11. Those plots should be validated once the modifications have been implemented in the well. With new production data, tuning of the gas injection is a trial procedure, always targeting an optimum production rate.  

Summary

Practical recommendations have been discussed, with the goal to keep the wells at their optimum condition. Those guidelines can be used for new wells or wells with plans to be remediated. Those are very practical guidelines, most of them not requiring any rig to be implemented. Those are glimpses of optimization processes through the analytical approach leading to production enhancement and OPEX/CAPEX cost reductions. The requirement then is the decision from management to look for opportunities to increase the NPV figures by putting resources with this goal in mind and the heart!