Eliminating liquid loading hikes Burgos basin production

Jan. 23, 2006
An integrated production-management process increased gas production from more than 600 Burgos basin wells that had experienced severe liquid loading.

An integrated production-management process increased gas production from more than 600 Burgos basin wells that had experienced severe liquid loading. Involved in the project were both Pemex Exploration and Production and Schlumberger Inc. professionals.

Project CISA (Contrato Integral de Sistemas Artificiales) began in late 2001 with the goal to optimize 650 gas wells by the end of November 2006 through elimination of current and future liquid load up in wells. The project applied fully integrated, closed-loop engineering starting with data preparation and ending with real-time production monitoring and optimization.

The production systems handle both immediate and expected conditions, especially the return of liquid loading. When a currently installed system no longer can handle liquid loading, due to natural production decline, the operations can combine systems. Ongoing results and measurements from the reservoir, wellbore, and surface-some in real time-provide data for the systems to optimize production continuously by modifying the initially applied solutions.

To date, the project has analyzed 614 wells; of these 99% have new production systems in place. Additional production currently attributed to the process is 105 MMcfd, proving the soundness of the integrated production-management-process approach.

Project considerations, strategy

When considering project strategy, the CISA team knew that determining actual well symptoms would enable a proper and reliable recognition and diagnosis of the problem. The limited initially available well data provided the initial engineering design for selecting and applying appropriate production methods for the Burgos gas wells. Data quality and management were key considerations.

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At launch, the strategic aims of the project included the following (Fig. 1):

• Develop a database containing all pertinent project information, such as well histories, measurements, and daily field supervision reports.

• Establish the actual performance status and potential of each well based on wellbore pressure and temperature measurements of each separated fluid (water and condensate).

• Analyze available data to select the most suitable production solution for each well, taking economic and technical limits into account.

• Thoroughly design and apply the selected production systems.

• Implement a real-time well monitoring and control system.

• Integrate relevant data, information, activities, and static and dynamic occurrences (real-time monitoring) to optimize production systems.

• Supervise and manage well production, including corrective actions, with the real-time network.

Problem analysis, recommendations

The analysis determined whether a well was producing at its potential and, if not, why not. The analysis also established the source and type of problem causing the limited production. From this analysis, the team selected the wells within the Project CISA portfolio that would benefit from corrective action.

Data gathering was the first step. Then the team classified within a flexible database the historical and real-time well data that helped with well problem analysis.

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In the next step, it determined how to organize the data and knowledge (both theoretical and practical) and then relate the data to field results (experience) so that subsequent corrective actions held the best possible chance of success (risk management). Fig. 2 shows the structure of the procedure for diagnosing the Burgos well problems.

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The procedure includes formalizing relevant expert knowledge by associating a list of possible problems with the corresponding symptoms (Table 1). The success of a problem diagnosis is related to the ability to connect extracted symptoms with possible problems. Because liquid loading had been the most prominent problem in Burgos area gas wells, the team fashioned some special rules into a problem correlation chart to help with the diagnosis (Table 2).

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After identifying a problem, the team applied the best possible course of remedial action. It devised a rules table to assist with selecting a course of recommended actions (Table 3). Likewise, because multiple production systems might fit a given set of recommended actions and each system has specific characteristics, the team developed another set of specific rules to guide production system selection well by well (Table 4).

Production systems

The CISA project included two classes of production systems (Fig. 3). The first delivers continuous flow and the second enables intermittent operations. A combined production system approach also has led to significant improvements, as well. The flexibility of combined systems enables easy modification of operating parameters and adaptability to meet the dynamic (transient) Burgos basin well conditions.

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While many production options can solve liquid loading, the use of coiled tubing is the most acceptable one for continuous flow. Not all wells, however, will flow naturally. In this case, the most frequently applied solution has been to combine the production systems for intermittent operation, such as the use of foam sticks and a motor valve. In fact, early results showed that combined production systems are the most efficient way to manage new liquid loading.

Table 5 shows the different production systems applied in the basin through December 2004.

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The team selected a composite nodal analysis procedure to model each well because liquid loading depends upon multiple factors such as pressure and temperature conditions both at the surface and downhole, as well as the composition of the gas and liquid (condensate) present (Fig. 4).

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The analysis used production data for simulating or predicting likely future well behavior. With limited data for a given well, the analysis included a multicriteria ranking model to select the most appropriate production system.

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Well analysis and problem diagnosis begins with validating and storing all available data in a project database. Next, what might be called a deterministic approach, the analysis builds a well model from these data. The model uses surface buildup and drawdown tests, interjecting different downhole and surface parameters, to identify multiple ways to produce a well without liquid loading.

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A system analysis also determines the factors that cause a well’s gas production to decrease and, in certain cases, identifies the problem type. The factors may include production system components that contribute to flow restrictions.

An accurate inflow performance profile requires quality test data and an appropriate inflow performance relationship. After the process determines an accurate inflow performance, it is possible to select the right model for the remaining production system components.

After application of a two-stage matching procedure, the analysis includes the simulation of the well behavior with a broad range of parameters (tubing diameter, choke size, system pressure, flow type, etc.). Composite system analysis for multiphase flow provides a way for determining the recompletion scenario that most likely would prolong production without liquid loading.

While reservoir pressure is a key parameter for reliable system analysis, it was unavailable in almost all analyzed cases. With one known gas-rate test and bottomhole flowing pressure, the analysis estimated the expected static bottomhole pressure with a newly developed model that uses an iterative procedure based on Mishra-Caudle and Fetkovich inflow-performance equations.

Another obstacle to overcome was how to model well behavior assuming that additional productive intervals would be opened. This is particularly difficult with intervals of varying and unknown productive characteristics. Both the distribution and length of the perforated intervals affect future well performance.

The analysis simulated well performance assuming that the well will be recompleted, using coiled tubing, between the existing uppermost and lowermost intervals. The idea is to add gas from the upper zones to maintain the gas velocity (production rate) greater than a predetermined critical gas rate. The operator could install a second motor valve to close off and open the casing so that upper zone gas would be diverted to the tubing to increase gas velocity and prevent the load-up process. Additional surface buildup tests would define the time and pressure when the motor valve should activate to close off the casing and open the tubing.

When the gas velocity in the coiled tubing is close to or less than critical velocity and additional gas from the annulus is insufficient to maintain operations without liquid loading, the motor valve would allow conventional, intermittent operations with the number of cycles determined from surface buildup and drawdown tests.

After analyzing more than 70% of the portfolio wells, the project team determined that the optimal solution for more than half of the wells was to install 1.75-2.0-in. coiled tubing. Because it is impossible to define the production characteristics for each interval (data unavailable), the team chose to install coiled tubing to increase gas velocity across the upper intervals, in some cases.

Simulation determined a minimal gas-velocity rate properly to control gas rate and pressure in the annulus and tubing. Using coiled tubing in combination with controlling the gas rate and pressure in the annulus and tubing, however, results in fluctuating flow conditions that cannot be simulated with conventional system analysis.

System analysis also helped determine when the use of coiled tubing will cause a very short flow period and rapid loading conditions. In this case, the reasonable solution is to produce the well intermittently. Selecting a suitable intermittent system involves use of surface pressure test and field survey data with different foaming agents (sticks or liquid).

Very often, the team selected a combined production system that uses intermittent operations along with the launching of foam sticks. Another option involves intermittent operations with only a motor valve or plunger lift.

Wellhead compressors were installed on wells with low-pressure reservoirs and limited liquid content. The team favored this solution especially when one compressor unit can handle the gas from several wells. For the desired payout, economic analysis has shown that 300-Mcfd production is required per compressor. This translates into about two to six wells per group, depending on the production rate per well.

The conventional system analysis procedure must be modified for simulating well behavior when liquid foaming agents are used. Specifically, the analysis requires determination of a modified flowing gradient, not discussed in this article.

In certain situations, especially when there is limited input data available for a well or when a well cannot flow under steady-state conditions, the team preferred to use a multicriteria-modeling system. For the CISA project, it established a two-tier classification and ranking of parameters related to liquid loading in the wellbore and reservoir that influence the production system selection.

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To date, the team has used the multicriteria model to analyze 100 wells with gas production less than 300 Mcfd (Fig. 5). The resulting recommendations represent a synthesis of knowledge gleaned from production data, problem diagnosis, well behavior predictions, economic evaluation, and technical solutions. Detailed studies and practical experience of the liquid loading problems in Burgos basin gas wells have shown that:

• Tubing diameter is the most important parameter influencing the initiation and intensity of liquid loading.

• Well completion type and design, specifically the location of the packer in relation to the productive intervals, are often critical factors in the origin of liquid loading.

• Low reservoir or bottomhole flowing pressure and wellbore temperature strongly influence liquid loading.

Well optimization

Well optimization is a continuous activity in the Burgos basin. Daily analysis consists of collecting data, monitoring well behavior, and then comparing actual data to historical results and initial analyses. If a well is not producing as previously predicted, the procedure is to use an optimization process to determine the possibility of implementing operational or production improvements.

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The optimization process takes into account the integration of all data, information, and events, both static and dynamic, throughout the production chain-reservoir through to surface facilities (Fig. 6). The process must analyze the new incoming data, from real-time and periodic well monitoring, in a timely manner to determine if the opportunity exists for optimization. The optimization results are the basis of a new action plan for the well.

The process requires the prioritization of the optimization candidates in a comprehensive way, taking into account the reservoir, wells, and surface characteristics. The production system in place determines the priority of the specific optimization activities.

Production management

Real-time production management, which is critical to the optimization process, began on Burgos basin wells in August 2003. The selected field telemetry provides Pemex with remote internet access to production data from the wells for improving production-management service quality, enable real-time well optimization, and reduce operating costs.

The wells have intelligent remote telemetry units controlled by an AutoCyclePlus (ACP) system. Authorized Pemex employees receive the real-time data through the internet using Schlumberger’s real-time production system.

The real-time well data allows for the possibility to control, manage, and diagnose well problems more automatically with both the knowledge and experience of service center engineers and a system of expert rules derived from prior project results. The system can recommend practical solutions, according to the previously described methodology.

To date, 41 wells have real-time telemetry functionality. The ultimate goal is to install on each well a complete intermittent-operations control operated with remotely sent commands. This control will use a map interface to select the well location, launch various reports for that well, and select execution steps.

Example case

Pemex completed Well Cuitlahuac-958 as a monobore with 3.5-in. tubing and one perforated and fractured interval (3,130-3,140 m). Gas production of 10.2 MMcfd, with 5,780-psi wellhead tubing pressure, began on Feb. 23, 2002, through a 2064-in. choke. Although this initial rate was high, the rate began declining within 2 months.

While production stabilized in the range of 8.8 to 10 MMcfd, the wellhead pressure continued to decline. An increase in the choke size to 2464-in. improved the production to 11.5 MMcfd with a 4,175-psi wellhead tubing pressure, but this increase was short lived. The production and tubing pressure again began to decline.

In the following 4 months, wellhead pressure and gas production declined to 2,200 psi and 6 MMcfd, respectively. In the first 7 months, generally, gas production and wellhead pressure declined rapidly. A three-phase measurement performed on Sept. 25, 2002, showed a production of 1.59 MMcfd with a 1,763-psi wellhead pressure.

At that time, the well produced an average 71 b/d of condensate. With a system pressure of 980 psi, the well had a subsonic gas flow through the choke. The gradient pressure survey indicated high liquid content. The well was flowing below the calculated critical gas rate of 2.763 MMcfd and liquid loading had started.

The evaluation team explored whether installing small-diameter production tubing above the perforated interval would improve production. Using an estimated reservoir pressure of 3,550 psi and the known gas composition, it selected an appropriate correlation.

Once the model reproduced the behavior, the team performed a sensitivity analysis to solve the loading problem. Analysis revealed that the best option was to run a 2.0-in. velocity string to decrease the critical gas rate and extend natural flow. This string, installed Nov. 5, 2002, successfully solved the loading problem.

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After 1 year, the natural decline process continued and liquid loading began again. After adjustment of the nodal analysis model to the new conditions, a new sensitivity analysis (Fig. 7) recommended reducing the line pressure to 220 psig and increasing the choke size to at least 1864-in.

These recommendations, implemented Nov. 3, 2004, resulted in the well flowing without loading and with an increase of 78.2% in the production rate.

Project results

At the end of 2004, the project had completed analyzing 614 wells and new production systems had been installed on about 99% of these wells. Gas production had increased by 105 MMcfd since the start of project CISA in late 2001. With an average price of $2.27/Mcf, the Pemex investment in integrated production management to handle Burgos basin gas well loading has paid off manyfold.

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Fig. 8 shows the production results through yearend 2004.

The integrated project management system put in place, combined with the new real-time data access network, allows team knowledge and experience to be leveraged over and over again. Well control has become more precise and reliable. Pemex now can prevent more easily unwanted production losses and other problems, as well as optimized the production with its economic model.

The authors

Leticia Lilia De la Mora Mejía is an engineering supervisor for the CISA project, Mexico North, Pemex Exploration and Production, specializing in artificial lift systems. She holds a masters of engineering degree from the Universidad Nacional Autonoma de Mexico and is a member of the Petroleum Engineering Association of Mexico (Asociación de Ingenieros Petroleros de México) and the Colegio de Ingenieros Petroleros de México.

Eddi De la Vega Perez, is an engineering supervisor for the CISA project, Mexico North, Pemex Exploration and Production. He was previously employed by the Bufete Industrial Diseños y Proyectos. He holds a BS in petroleum engineering from the Universidad Nacional Autonoma de Mexico and is a member of the Colegio de Ingenieros Petroleros de Mexico.

Miso Solesa is an artificial lift and completion expert for Schlumberger. He is currently assigned to special artificial lift projects in Russia, and previously was project manager for the Pemex CISA project. Past employers have included NaftaGas and the University in Belgrade and Leoben. He holds a PhD in petroleum engineering from the Faculty of Mining and Geology, Belgrade. He is a member of the Serbien Engineering Academy and the SPE.

Otoniel Morales Martínez is an applications engineer, Mexico North, Schlumberger, and is responsible for optimization of the Pemex CISA project. He was previously employed by Instituto Mexicano del Petroleo, Halliburton Inc., and Camco de Mexico. He holds a BS in petroleum engineering from the Universidad Nacional Autonoma de Mexico.

José Luis Martínez Galván is an applications engineer, Mexico North, Schlumberger, and serves as the Pemex CISA project manager. He was previously employed by Instituto Mexicano del Petroleo, Universidad Nacional Autonoma de Mexico, and Camco de Mexico. He holds a BS in petroleum engineering from the Universidad Nacional Autonoma de Mexico.