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Predicting sand production
Predicting whether a well will produce fluids without producing sand has been the goal of many completion engineers and research projects. There are a number of analytical techniques and guidelines to assist in determining if sand control is necessary, but no technique has proven to be universally acceptable or completely accurate. In some geographic regions, guidelines and rules of thumb apply that have little validity in other areas of the world. Predicting whether a formation will or will not produce sand is not an exact science, and more refinement is needed. Until better prediction techniques are available, the best way of determining the need for sand control in a particular well is to perform an extended production test with a conventional completion and observe whether sand production occurs. Normally, it is not necessary to predict sand production on a well-by-well basis because wells in the same reservoir tend to behave similarly. The prediction required is on a reservoir-by-reservoir basis. However, initial good results may prove misleading, as reservoir and flow conditions change.
Operational and economic influences
The difficulty of determining whether sand control is required in a given well is compounded when the well is drilled in a remote area where there is no producing experience and where the various reservoir factors are slightly different from previously exploited regions. Even if the reservoir and formation properties are almost identical to other developments, the operating conditions and risks may be such that different strategies apply. One example might be a subsea project, as opposed to a land development project. Here, the consequences and risks associated with sand production are significantly different because of differing costs and risks associated with remedial well operations; hence, the decision to use a sand-control technique is both an economic and operational decision that must be made with limited data.
The decision is complicated by the fact that sand-control techniques, such as gravel packing, are expensive and can restrict well productivity if not performed properly. Therefore, gravel packing cannot be applied indiscriminately when the possibility for sand production from a well is unknown. Making the decision whether to gravel pack is fairly easy if the formation material is either hard (no sand production) or weak (sand production). The difficulty arises when the strength of the formation material is marginal. At that point, the decision normally ceases to be primarily a technical issue but more of an economic and risk management exercise. If there is uncertainty, the conservative approach is to always apply sand-control completions. This obviously will solve the sand production problem but will also increase costs and may reduce well productivity. If sand control was actually unnecessary, the implementation of sand-control completions was a bad economic decision.
The procedure followed by most, to consider whether sand control is required, is to determine the hardness of the formation rock (i.e., the rock’s compressive strength). Because the rock’s compressive strength has the same units as the pressure difference between the reservoir and the well (the drawdown), the two parameters can be directly compared, and drawdown limits for specific wells can be determined. Research performed in the early 1970s showed that rock failed and began to produce sand when the drawdown pressure was more than about 1.7 times the compressive strength. As an example, formation sand with a compressive strength of 1,000 psi would not fail or begin to produce sand until the drawdown exceeded 1,700 psi. Others use Brinnell hardness as an indicator of whether to apply sand control. The Brinnell hardness of the rock is related to the compressive strength but is not as convenient to use because the units of hardness are dimensionless and cannot be related to drawdown as easily as compressive strength.
The sonic log can be used as a way of addressing the sand production potential of wells. The sonic log records the time required for sound waves to travel through the formation, usually in microseconds. The porosity is related to formation strength and the sonic travel time. Short travel times, less than 50 microseconds, indicate low porosity and hard, dense rock; long travel times, 95 microseconds or greater, are associated with soft, low-density, high-porosity rock. A common technique used for determining whether sand control is required in a given geologic area is to correlate incidences of sand production with the sonic log readings above and below the sand production that has been observed. This establishes a quick screening method for the need for sand control. The use of this method requires calibration against particular geologic formations to be reliable.
Formation properties log
Certain well logs, such as the sonic log and density and neutron devices, are indicators of porosity and formation hardness. For a particular formation, a low-density reading indicates high porosity. The neutron logs are primarily an indicator of porosity. Several logging companies offer a formation properties log that uses the results of the sonic, density, and neutron logs to determine if a formation will produce formation material at certain levels of drawdown. This calculation identifies weak and strong intervals; the weaker ones are more prone to produce sand. While the formation properties log has been used for over 20 years, experience has shown that this log usually overpredicts the need for sand control.
The porosity of a formation can be used as a guideline as to whether sand control is needed. If the formation porosity is greater than 30%, the probability of the need for sand control is high because of the lack of cementation. Conversely, if the porosity is less than 20%, the need for sand control will probably be minimal because the sand has some consolidation. The porosity range between 20 to 30% is where uncertainty usually exists. In natural media, porosity is related to the degree of cementation present in a formation; thus, the basis for this technique is understandable. Porosity information can be derived from well logs or laboratory core analysis.
The pressure drawdown associated with production may be an indicator of potential formation sand production. No sand production may occur with small pressure drawdown around the well, whereas excessive drawdown can cause the formation to fail and produce sand at unacceptable levels. The amount of pressure drawdown is normally associated with the formation permeability and the viscosity of the produced fluids. Low viscosity fluids, such as gas, experience smaller drawdowns, as opposed to the drawdown that would be associated with a 1,000-cp fluid produced from the same interval. Hence, higher sand production is usually associated with viscous fluids.
Finite element analysis
The most sophisticated approach to predicting sand production is the use of geomechanical numerical models developed to analyze fluid flow through the reservoir in relation to the formation strength. The effect of formation stress, associated with fluid flow in the immediate region around the wellbore, is simultaneously computed with finite element analysis. While this approach is by far the most rigorous, it requires an accurate knowledge of the formation’s strength around the well in both the elastic and plastic regions where the formation begins to fail. Input data on both regions are difficult to acquire with a high degree of accuracy under actual downhole conditions. This is the major difficulty with this approach. The finite element analysis method is good from the viewpoint of comparing one interval with another; however, the absolute values calculated may not represent actual formation behavior.
The effect of time on the production of formation sand is sometimes considered to be an issue; however, there are no data that suggest that time alone is a factor. There have been undocumented claims that produced fluids could possibly dissolve the formation’s natural cementing materials, but the data are not substantiated.
Predicting when multiphase fluid flow will begin can also be an aid. Many cases can be cited where wells produced sand free until water production began, but produced unacceptable amounts afterwards. The reason for the increased sand production is caused by two primary phenomena: the movement of water-wet fines and relative permeability effects. Most formation fines are water wet and, as a consequence, immobile when a hydrocarbon phase is the sole produced fluid because hydrocarbons occupy the majority of the pore space. However, when the water saturation is increased to the point that water becomes mobile, the formation fines begin the move with the wetting phase (water), which creates localized plugging in the pore throats of the porous media. Additionally, when two-phase flow occurs, increased drawdown is experienced because two phases flowing together have more resistance to flow than either fluid alone. These relative permeability effects can increase the drawdown around the well by as much as a factor of 5 per unit of production. The result of fines migration, plugging, and reduced relative permeability around the well increases the drawdown to the point that it may exceed the strength of the formation. The consequences can be excessive sand production. The severity of fines migration varies from formation to formation and whether gas or liquid is being produced.
- Penberthy, W.L. Jr. and Shaughnessy, C.M. 1992. Sand Control, 1, 11-17. Richardson, Texas: Monograph Series, SPE.
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