Location of the Abkatun oil field, on the Gulf of Mexico coastline.
An efficient tool based on laboratory measurements, well production data, and numerical simulation has been developed to predict the formation of heavy organic deposits (asphaltenes, petroleum resins, and waxes) from blocking production flows from oil wells in many Mexican fields.
"The approach is based on laboratory measurements, in which pressure-preserved, live-oil samples are analyzed," explains Carlos Lira-Galeana, Senior Research Scientist and Director of the Thermodynamics Research Laboratory of the Mexican Petroleum Institute (IMP) in Mexico City.
"Samples of live crude oil are taken from the bottom of the wells affected by (or prone to) deposition, and their chemical composition and multiphase behavior are analyzed using advanced laboratory techniques," he added.
At that point, it can be identified whether a given crude type is sensitive to forming solids from the simulated reservoir conditions to the pressures and temperatures at the surface of the well. "We look at those conditions in which solids may form when the oil is expanded from the reservoir pressure and temperature to those conditions prevailing at the wellhead, the well choke, and surface separators for handling oil production," he said.
Using production data from the oil well, compositional flow calculations are guided to predict current and alternative conditions in which the well would flow upon changes in the well string geometry, production rate, and time. "We now have the ability to make accurate predictions of how, when and where those deposits will occur in a well or an oil field. This is important in planning the production of a field over time," Dr. Lira-Galeana said.
The heavy organic material in crude oil (asphaltenes, waxes, and resins) has been the subject of extensive research over the past century. Although there are well-known remediation methods for mitigation (chemical injection, mechanical or thermal operations in the well), there had been no reliable methodology for predicting or diagnosing the appearance of these problems for a given system.
Combined behavior
The technology developed by the IMP combines information on the thermodynamic, kinetic, and field-level behavior of the oil fluid/oil well system. The client provides the oil samples and data related to its production system. The researchers analyze what would happen with that system as the oil moves upwards the production pipeline. - Measured asphaltene precipitation envelope (APE) for the Kanaab-101 live-oil fluid.
"All over the world, the crude oil being produced is becoming more complex, heavier, and more problematic. For asphaltenes, this problem also becomes more noticeable in the case of mature oil fields, in which the oil has reached its bubble-point pressure at reservoir temperature. At that point, gas is liberated and this situation may allow asphaltenes to drop out from solution", says Lira-Galeana.
From the predictive nature of this approach, one has the additional value of being able to propose what kind of control technique - from those available in the market - is likely to be most appropriate for dealing with each problem. Commercially available control techniques now include magnetic, ultrasonic, and other tools for dispersion.
"This is an expensive problem to solve for production engineers. Commercial chemical solvents are a typical but high-cost remedy and they have to be applied frequently, as asphaltene deposits tend to form again soon after production improves. In a typical situation, we have seen production drop to half in just a few months, due to solids being deposited. Monthly expenditures on the injection of chemicals may reach $800,000. If you add to that the value of deferred production (as a result of the blockage), you may then have about $25 to $30 million a year in losses for a typical oil well," Lira-Galeana said.
The IMP has been applying its technology to both onshore and offshore fields in the south of Mexico. Work in the offshore area began in 1997. There is no doubt that some of the wells on these fields are important oil producers (as much as 8,000 b/d).
Case study: Kanaab-101
Predicted results for the Kannab-101 oil well flow rate of 4000 b/d.
The procedure cited above was used in solving the problem for a Mexican offshore well. The Kanaab-101 oil well in the Abkatun oil field started to produce hydrocarbons (29.5 degrees API oil) from the 15,026-15,091 ft depth interval in mid-July, 1996, with an initial production rate of 6,680 b/d.
When performing a production test on Nov. 24, 1996, both the downhole wire caliper and the probe got trapped. A major well operation that involved extraction of the whole well string led to the observation that severe asphaltene deposition had occurred on the pipeline walls from the 10,482 ft well interval. Samples of field deposits were then sent to laboratory analysis, confirming that the blocking material was basically made up of asphaltenes.
To mitigate the problem, the production tubing was changed in full in a 31-day operation. The total cost of replacing the tubing amounted to $4,320,000, owing to deferred production. Later in May 1997, the wellhead pressure and oil production rate started to decrease significantly, with the result that, after a two-stage cleaning and stimulation procedure, production levels registered were those shown in Table 1. Thus, after the well recovered reasonable production values, it was decided to implement technology that might provide a longer-lasting solution, in both economic and operational terms, on the well.
After discussing the problem with the client (Pemex), pressure-preserved, live-oil samples were taken from the bottom of the well and then used to obtain the thermodynamic conditions in which asphaltenes tend to precipitate from solution. "To predict the behavioral features of asphaltene formation and plugging in the well as a function of both well geometry and flow rate, we applied our predictive approach, which combines the features (shown), together with the flow characteristics in the well," said Lira-Galeana.
The predicted results show the flocculation trend downpipe, for cases in which:
- The current production scenario (4,000 b/d, well-string geometry of 3.5-in.) is reproduced
- A sensitivity analysis (at constant-string geometry) is performed to various production rates
- Both the well-flow rate and a reduction in the wellstring are varied.
Sensitivity analysis to various production rates was performed for the Kanaab-101 oil well.
The initial flocculation point (IFP) is estimated within 2%, compared to the value obser-ved in the field (predicted IFP = 10,250 ft; observed IFP = 10,482 ft, respectively). The good agreement between the predicted and the field-observed IFPs permitted the application of compositional flow calculations in the well, by which the variation of both well geometry and the combination of well geometry plus variable flow rate were attained.
According to the results, the organic-deposition blocking for this well will always lie in a region which is far from the producing interval, when the afore-mentioned variations could happen. Transient-flow predictions, as well as the evaluation of control schemes for deposition (chemical injection, artificial lift, etc.), can also be performed and monitored by the proposed approach.
Based upon the economic and technical results, the client decided to install a commercially-available tool at a location close to the IFP point, by which the precipitated asphaltenes remain dispersed when flowing up the well. The tool was installed in early February, 1998, and, after a couple of cleaning and stimulation operations, the well has continued to produce an average rate of 3,914-3,970 b/d of crude oil over almost two years of operation.
The economic savings on Kanaab-101 reached close to $4 million, due to the elimination of materials, well services, equipment, and dead-times, among other expenses. Furthermore, the additional oil recovered as a result of the present study reaches to about 1 million bbl of production up to the present time.
IMP researcher Lira Galeana concluded that "the best scenario is, of course, that no blockage in the tubing should ever take place. This requires monitoring when it might occur based on our laboratory studies. We can make specific recommendations on what remediation techniques should be applied for a given case. However, it is up to the producer to make a final decision on which of a wide range of techniques one can use. Investment considerations are obviously a key factor influencing such a decision."
