Injeção de água em poços de petróleo

Injeção de água em poços de petróleo

(Parte 1 de 3)

Copyright 2006, Society of Petroleum Engineers

This paper was prepared for presentation at the 2006 SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, U.S.A., 24–27 September 2006.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

This paper illustrates how practical application of surveillance and monitoring principles are keys to understanding reservoir performance and identifying opportunities that will improve ultimate oil recovery. Implementation of various principles recommended by industry experts is presented using examples from fields currently in production.

Practices on how to process valuable information and analyze data from different perspectives are presented in a methodical way on the following bases: field, block, pattern, and wells. A novel diagnostic plot is presented to assess well performance and identify problem wells for the field.

Results from the application of these practices in a pilot area are shared, indicating that the nominal decline rate improved from 3% to 18% per year without any infill drilling. The change in the decline rate is primarily attributed to effective waterflood management with a methodical approach, employing an integrated multi-functional team.

Although the suggested techniques can be applied to any oil field undergoing a waterflood, they are of great value to mature waterfloods that involve significant production history. In these cases, prioritization is a key aspect to maintain focus on the opportunities that will add most value during the final period of the depletion cycle. Case studies illustrating the best surveillance practices are discussed.

Introduction

Surveillance and monitoring techniques were first discussed in SPE literature in the early 1960s1. Since then, several highly recognized authors have published related materials2,3,4,5,6,7,8. Industry experts recommend the following valuable principles:

• The key ingredient of any surveillance program is planning and accurate data collection. • To understand reservoir flows and reduce non- uniqueness in interpretations, it is crucial to implement a multilevel surveillance effort.

• A single technique in isolation is not generally indicative because different parameters can cause similar plot signatures.

• Controlled waterflooding through the use of pattern balancing requires time and technical (engineering and geological) efforts during the life of the project.

• Valuable insights into the performance of the waterflood can be gained from individual well plots such as Hall plots.

• Surveillance techniques should always be a precursor to in-depth studies, including numerical simulation.

A process to consistently evaluate the performance of a reservoir—from field to block to pattern to well level—is discussed with the help of real-life examples. Type plots and maps are used to identify opportunities and promote team discussions to effectively manage a reservoir undergoing waterflood. Production history and basic reservoir characterization serve as primary input variables for the recommended analysis.

Table 1 describes the main characteristics of the fields presented as examples.

The first example is from El Trapial field in Argentina in

South America. This is a sandstone reservoir located onshore with a primary drive mechanism of solution gas drive. The average permeability and porosity are 75 mD and 17%, respectively. The field was discovered in 1991, and water injection started in 1993.

The second example corresponds to the Bangko field located in Indonesia, southeast Asia. This sandstone reservoir is located onshore with aquifer support. The average permeability and porosity are 530 mD and 25%, respectively. The field was discovered in 1970, and water injection started in 1992.

The third and last example corresponds to the Meren field located in Nigeria, west Africa. This sandstone reservoir is located offshore with a mixed primary drive mechanism, including aquifer support and gas cap expansion. The average permeability and porosity are 1,0 mD and 27%, respectively. The field was discovered in 1965, and water injection started in 1984.

SPE 102200

Waterflooding Surveillance and Monitoring: Putting Principles Into Practice M. Terrado, S. Yudono, and G. Thakur, Chevron Energy Technology Co.

2 SPE 102200

A Multilevel Approach

After reviewing many waterflood case studies, one of the key lessons learned is to use a methodical approach to understand where the opportunities exist, thus preventing the implementation of biased action plans or hastily made judgments. This is especially important under the current environment where optimization of human and capital resources is a critical issue.

The proposed procedure goes from a large scale to the detailed as follows.

Field Level

When looking at a field under waterflood, the first intent should be to determine the overall health of the asset. The following are the key aspects to investigate:

1. What is the primary drive mechanism or mix of mechanisms? 2. What is the current recovery factor and how many pore volumes of water have been injected? 3. How is the static reservoir pressure behaving through time? 4. What are the monthly and cumulative voidage replacement ratios? 5. How is the total fluid production behaving, i.e., is it increasing, flat, or decreasing? 6. How is the gas oil ratio performing? 7. What are the water production and water/oil ratio trends? 8. How much is the water injection rate and how does it compare to the total reservoir voidage in reservoir barrels? 9. How much excess capacity is available for production and injection? Will field improvement be restricted by limitations of current facilities? 10. How do the productivity and injectivity per well compare? 1. Is injection above or below the fracturing pressure? Does the fracturing pressure change from one part of the field to another? Does it change as a function of the reservoir pressure in a given part of the field?

Voidage replacement ratio (VRR). VRR through time will give an idea of whether or not enough water is being injected and available in the field. Both monthly and cumulative values should be monitored. When monthly VRR is greater than 1 and reservoir pressure is not increasing, out-of-zone injection loss from the target zone or severe thieving is suspected. When monthly VRR is less than 1 and reservoir pressure is not decreasing, influx of fluids is suspected, e.g., aquifer influx into the control area. Plotting the oil rate (log scale) versus time along with the VRR versus time helps one understand the relationship between these two variables.

Figure 1 shows El Trapial field where a direct relationship between VRR and oil production rate is observed. Oil rate declines when VRR drops below 100% and it improves when VRR is close to or above 100%. It is important to mention that no aquifer support exists in this field.

The second example, shown in Figure 2, corresponds to

Bangko field where aquifer support does exist. It shows that oil rate is not as dependent on VRR as in the first example.

The last example, shown in Figure 3, corresponds to Meren field where some aquifer support exists.

Mapping. Time lapsed maps of gas/oil ratio (GOR), water cut (Wcut), dynamic and static pressures are easy to obtain and extremely useful. Once these maps are prepared, it is important to spend a reasonable amount of time looking for the following characteristics:

• Areas with low Wcut (<70%), GOR above dissolved gas/oil ratio (Rs), and low static pressures should be assigned a high priority. Solutions to these cases include incrementally increasing the injection rates, drilling new injectors or converting producers to injectors.

• Areas with high Wcut (>95%), GOR similar to Rs, and high well fluid dynamic levels should be reviewed for pumping off and, if necessary, reduce the water injection, especially if water is a scarce resource.

• Examination of a dynamic bottomhole flowing pressure map will indicate if producers are efficiently being pumped off. It is important to keep the levels down to allow maximum pressure gradient and therefore, maximum flow between injectors and producers. Additionally, a lower dynamic pressure minimizes cross flow effects between layers.

In calculating theoretical water injection, flood-front maps will aid in visualizing which areas are mature and which are in need of more water injection points. Since there are many assumptions regarding fluid flow when calculating the flood front (e.g., the existence of good cement behind pipe), this map should be taken into consideration on a qualitative basis only.

Figures 4 through 7 illustrate maps of El Trapial field for a given date. A detailed evaluation of these concludes that the waterflood has different levels of maturity. The south is more mature with high Wcut, GOR values close to Rs, and static pressure near original values. At the same time, the north area shows low Wcut, GOR greater than Rs, and lower static pressures, suggesting an area with improvement opportunities. Infill drilling and conversions could be recommended after looking at the next levels of evaluation.

Plotting the total liquid production. Examination of the total liquid production trend through time can give insights to the following:

1. Is the total liquid production flat? Is this because of facilities constraints?

2. Is the total liquid production increasing? How much of this is owing to new drills and how much is resulting from base production optimization?

3. Is there a direct relationship between VRR and liquid production?

Figure 8 shows Bangko field data where maximum facility capacity has been reached at a total liquid rate of

SPE 102200 3

550 thousand B/D. Waterflood optimization under this condition is limited, thus, upgrading the facilities is currently under study.

Figure 9 shows Meren field data. Notice that VRR has been above 100% for the last 15 years with an increasing total liquid production. This has resulted in stable oil rates as seen in Figure 3.

Pore volumes injected (PVI). Recovery factor (RF) and water cut (Wcut) versus PVI plots are useful in understanding the drive mechanism and the maturity of an asset. This is a simple exercise and a very useful benchmarking metric.

Figures 10 and 1 show these plots for the three fields presented. Figure 10 suggests that Bangko field has some aquifer support as implied by the recovery factor value of 2% prior to water injection. The field office has confirmed this point, based on the history of pressure support. The same figure shows a recovery factor for Meren Field of about 20% prior to the initiation of water injection. This estimate of RF is the result of the gas-cap expansion and some aquifer support in the flanks of the field.

Figure 1 shows that the Wcut for Bangko field has been approximately 80% from the beginning, a typical characteristic of aquifer supported fields. By contrast, El Trapial field, which does not have aquifer support, required approximately 0.4 PVI to reach the same Wcut level.

Validating the pattern configuration. A good exercise to perform at this level is to calculate the average total fluid production and injection rate per well at reservoir conditions. After doing so, the ratio of injection to production for the average well is calculated and referred to as the I/P ratio. This value should be close to the one given by the pattern injection selected for the field. As a reminder, a five-spot pattern gives a 1:1 I/P ratio making it necessary to have one injector for each producer. If the I/P ratio is close to 2:1, an inverted seven-spot pattern will be optimal and a 3:1 I/P ratio will be suitable for an inverted nine-spot pattern7.

Table 1 shows the I/P ratios for the three given examples.

This ratio is approximately 2:1 for El Trapial, therefore an inverted seven-spot pattern was chosen for the field. Had the decision been made to develop using a five-spot pattern, the number of injector wells would have been much higher and unnecessary capital expenditures would have occurred.

In the case of Bangko and Meren fields, the ratio is between 4 and 7, indicating a much higher value of injection relative to production rates. These two cases employed peripheral waterfloods with average permeabilities in the range of 0.5 to 10 Darcys, higher reservoir continuity and conductivity, and some aquifer support.

The ABC plot. When looking at a field with hundreds of wells, identifying the performance of all wells can be overwhelming. Additionally, well review meetings are usually time consuming and difficult to keep focused. A different approach has been taken by using a plot called the “After-Before-Compare” or “ABC” plot. This plot uses well test production data from two distinct dates and compares oil and water rate between those dates. The same dates are used for all the wells.

In the X-axis, the ratio of current water rate to previous water rate is plotted. In the Y-axis, the ratio of current oil rate to previous oil rate is plotted. Each point in the chart represents a single well with which several behaviors can be quickly identified:

• WELLS WITHOUT CHANGE: These are wells that fall within the (1, 1) area coordinate point. It is not necessary to spend time on these wells as long as they have been properly and frequently tested throughout the selected period.

• TOTAL LIQUID RATE INCREASE: These are the wells that responded to the water injection. They fall on the 45 degree slope line and above the (1, 1) coordinate point.

• TOTAL LIQUID RATE DECREASE: These are problem wells. They fall on the 45 degree slope line and below the (1, 1) coordinate point. Team discussions should focus on root causes. The first intent should be to differentiate if the cause is a result of artificial lift efficiency or reservoir conditions.

• WATER CUT INCREASE: These are the wells that fall on the lower right part of the 45 degree slope line. This is the expected behavior of wells in a waterflood asset; however, special attention should be given to wells falling outside the overall trend. Channeling may be causing a higher than usual behavior.

(Parte 1 de 3)

Comentários