Migration ofsandwithin the reservoircan present major obstacles to well production through reduced production rates, sand bridging, erosion of equipment, and sand disposal and removal. Our sand control services begin with an in-depth analysis of the reservoir and well conditions.
Based on your unique needs, wethenprovide specialized surface and downhole equipment,including gravel pack packers and screens, surface pumping equipment, fluid systems, and filtration systems, all supportedbycompletion service so you canmaximizevalue from your assets.
Multizone sand control completion systems are proven to save valuable rig time. Halliburton has a long, successful history withsingle-tripmultizone sand control systems that save days of rig time over stacked sand control systems, capture short, lowreserve intervals that would normally be bypassed, and reduce risk by helping eliminatethe need torun and retrievepacker plugs.
These screened pipe joints positioned in the wellbore, opposite formation perforations, block sand while allowing oil or water to flow through. Halliburton screen technology offers operators every conceivable advantage: precise particle size control, high strength and durability, unbeatable corrosion resistance, high pressure tolerance, increased containment capacity, superior erosion resistance,and backwash efficiency. They alsofeatureautomatic verification and real-time screen gauge manipulation.
We design ourinflow control devices (ICD) toimprove completion performance and efficiency by balancing inflow throughout the length of a completion. Autonomous ICDs restrict water and gas production to increase recoverable reserves and extend well production. Both technologies simplify sand control completions while increasing reliability.
Stimulation services have a simple goal: to maximize the value of the operator's assets. Halliburton helps achieve this goal with a wide range stimulation technologies, including advanced fluid systems, pumping capabilities and conductivity endurance technology.
Sand control procedures and practices vary throughout the world - and Halliburton's experience in the global marketplace ensure that our products and systems precisely match the character and requirements of specific formations.
Sand Production is the migration of the formation sand induced by the flow of reservoir fluids. It is initiated when the rocks around the perforations fail and the fluids thrust the loose grains into the borehole. It takes place when the reservoir fluid flow outpaces an assertive threshold which depends on factors like stress state, reservoir rock consistency and the way of completion which is used around the well.
The sand particles are first disintegrated from their parent rock before flowing with the reservoir fluids into the borehole. This can take place when the reservoir rocks have low formation strength and they fail under the conditions of in-situ and the imposed stress gets changed because of the hydrocarbon production.
Completion engineers are required to know the conditions at which the well can produce sand. In exploratory wells, the completion engineers use sand flow test to assess the Sand Production. The engineers must have a detailed knowledge of in-situ, mechanical strength of the formation and the ways in which rocks can fail so that they can predict the Sand Production. After establishing that at the planned production rates the sand is expected to be produced and the engineers choose a strategy to restrict the Sand Production.
Petropedia Terms: # A B C D E F G H I J K L M N O P Q R S T U V W X Y Z
Permeability: Permeability refers to the capacity of a rock layer (formation) to transmit water or other fluids, in this case, includes oil and gas. The standard unit for permeability is the Darcy (d) or millidarcy (md). Meanwhile, relative permeability is a dimensionless ratio that reflects the capability of oil, water, or gas to move through the formation relative to a single-phase fluid. Most commonly referred fluid would be water.
Porosity: Porosity determines the reservoir storage capacity. Commonly known as pore-volume, or bulk volume and can either be represented as a fraction or a percentage. Typical hydrocarbon reservoirs are composed of sedimentary rocks in which porosity values generally between 10-40% in a sandstone and from 5-25% in carbonates.
Capillary Pressure: The difference in pressure across the interface between two phases or pressure results from interactions of forcing acting within and between fluids and their bounding solids. The theory that covers wettability.
Sand control management refers to a management system focused on minimizing sand production in a oil or gas well. Sand production will cause erosion and wear of the production facilities and equipment.
Sand control is common in well completion in soft formation area. Soft formation area refers to a formation with compressive strength of rocks less than 1,000 psi. In those wells, we can expect production with formation sands or fines.
Normally, formation should be both porous and permeable in order for the hydrocarbon to flow into the wellbore. So, provided the cement job and perforation is done well, hydrocarbon would easily flow from the formation into the wellbore.
If youre familiar with Darcys law, a law that illustrates the fluid flow in a porous medium, you might know that in unconsolidated sandstone reservoirs with permeability between 0.5 to 0.8 Darcy are most susceptible to sand production.
So, sand control would be dependent on the sand production rate, the equipment sensitivity such as resistance to erosion, separator capacity, sand evacuation, or disposal and if the well uses any artificial lift system.
Fluid flows from a region of higher pressure into a lower pressure region. So, fluid flow from the formation into the wellbore is due to the differential pressure between the reservoir and the wellbore. However, if the compression strength of rocks in the formation is not strong enough to hold the sand in place, the likelihood of sand to be entrained (or sweep away) together with the production fluid is higher.
Therefore, in such cases, we need to restrain the sand from being produced together with the hydrocarbon. Some might call this as sand exclusion, Which basically means as the name suggest to exclude the sand from production flow.
Sand exclusion is required wherever the natural compression strength of the formation is not enough to hold the sand grains in place. This can happens either at the initial production phase, or at a later production phase depending on the well profile and on when sand is started to be an issue.
The frictional force meanwhile is related to the confining or overburden stresses. These stresses causes the rock to fail. The stress that causes the rock to fail includes the mechanical stress that results from overburden and drag forces associated from viscous flow of formation fluids through the rock matrix.
Meanwhile, capillary forces can also contribute to sand production. Usually, sand production would start when water production began. The onset of water production will lead to the dislodging of sand grains and swelling of the clay mineral.
We need to maintain the sand production from any well is below the acceptable level at anticipated flow rates (meaning at X flow rate, sand production from the well should not exceed Y kg of sand produced). This is crucial in production planning since it is tied in to the unit production cost of hydrocarbon produced and surface and subsurface facility equipment integrity.
Since compression strength is the primary force holding the sand in place, the lack of cementation bond between sand grains is key reason why sand production increases. This could be in terms of lose sands or unconsolidated sands.
This is an indication of how strong the sand grains are bounded together. The cement job performed in well completion is a secondary geological process to further consolidate (bond together) the sand grains.
Other than that changes change in reservoir conditions might also leads to an increase of sand production. Remember that earlier on, we mentioned that sand control could be in place during the initial production phase or at a later production phase.
Sand arch is a cap of interlocking sand grains which is stable at constant drawdown and flowing. These sand arch function as a natural sand-screen, preventing sand movement from the formation into the perforation tunnel and into the wellbore.
A simple mental picture would be like this: A highly viscous fluid flowing into the wellbore is pushing the sand grains in around the perforation into wellbore together with them. Simply because the sand grain can no longer withstand the forces exerted by the moving fluid.
So, a decrease in reservoir pressure or reservoir depletion at the later stage of production could also lead to an increase in sand production. Not only that, in the later stage of the production phase, whereby water-breakthrough happens or water conning will cause the dislodging of sand grains and swelling of clay minerals around the perforation.
The effects of sand production is almost always bad. Regardless, short or long term productivity of the well. Some wells completion and surface facility would be able to handle certain amount of sand production, but most of the time, we need sand control measures.
If the production flowrate is enough to carry sand up the tubing, the sand maybe trapped in multiple surface equipment such as separators, heat exchanger, etc. And these sand will affect those equipment efficiency.
This will happen if the production flowrate does not have enough power to carry the sand to the surface. So, sand buildup will happen in the downhole. Sand might start to fill up the production casing.
In highly productive wells, wells where fluid is flowing with high flowrate and hence, increasing the amount of sand carry out will lead to erosion both downhole and at surface facility. Especially at bend areas.
These increment leads to the well to collapse only after a few months. This is due to the increment of empty spaces or void in the formation, left by the sand. And these spaces can only gets bigger, wider.
So, when the void becomes large enough, the overlying formation might crumbles and collapse. When this happens, the well will either produced at lower permeability or quits altogether. The one I saw, quits.
Meanwhile, in a wild cat wells, or exploratory wells, a sand flow test could be used to assess the reservoir formation stability and compressive strength. A sand flow test involves sand production being detected and measured using drill stem test (DST).
Sand production might be affected by production flow rate. Something that can be experimented upon during the exploratory well (exploration phase). So, by trying out different flow rates until sand production started, the anticipated flow capacity of the completion is reached or the maximum drawdown is achieved we can get some quantitative information to form strategy on how to operates the well.
Besides that, down-hole-wireline log measurements can also provide data profiles of the well, but, as of now, Im not really sure that there are logging tools which can yields a direct measurement of rock strength (compressive strength).
The rule of thumb to consider whether sand control measure is needed or not is generally based on the hardness of the formation rock. Well, hardness of the formation rock refers to the formation rock compressive strength which is the primary forces holding the sand in place.
Some research suggests that there is a relationship between the compressive strength and sand production. The relationship indicates that the rock formation would start to failed and began to produce sand when the drawdown pressure is 1.7 times the compressive strength.
The goal of log analysis is to map out the downhole reservoir characteristics porosity, fluid saturation and permeability. However, the tool only measure gamma ray or neutron count rates at cleverly positioned detectors.
Generally, if the formation porosity is greater than 30%, the likelihood that a sand control system is required is higher. This is because of the lack of cementation (the bond of sand in the formation).
Remember that porosity is related to the degree of cementation present in a formation. Cementation here does not refer to cement from cementing job, but refers to the material in the rock between the grains that binds the grains together.
But with respect to predicting sand production, lab experiments on recovered core samples can help to determine data on rock strength (compressive strength) which is the primary force in holding the sand in place.
This information is a valuable piece of information in developing and planning for the optimized well production profile throughout its lifetime. Meaning, how much to produce and when to produce so that operators can optimized production operation for best return on investment.
My final paper for my Bachelorss degree was on a predictive mathematical model of nitrization on stainless steel. As far as I know, it has been cited by over 9000 times, and my name was cited quite a lot. So, in general I love mathematical modelling. It could also be used as an algorithm in decision making. You know, to take emotion out of decision making.
Well, I dont recommend you to do it own your own. Hire someone specialized on the field. To do such thing, you need equipment and the skill. Most of the time, it is cheaper to outsource. Besides, being a client is so much fun.
FEA requires an accurate knowledge of the formation strength around the well where the formation would begins to fail. So, input data for such an analysis can be difficult to get. Thats the main limitation to FEA.
Thick-Walled Cylinder (TWC) are circular cylinders approximately 3 inches in height and 1.5 inches in diameter, with a co-axial 0.5-inch diameter hole drilled through the sample. Confining stress is applied to the outside surface until overburden pressure or cylinder started producing sand.
The thick wall cylinder test (TWC) is used to estimate the perforation collapse strength of the intervals. It is derived directly from TWCs strength. The perforation collapse can occur when the vertical effective stress near the wellbore. Flowing bottomhole pressure must be bigger than the critical value.
This would provides direct measure of pressures under which downhole will start producing sand or cause other problem. Such information is essential in order to understand the controlled parameter in which operators can maintain wellbore stability.
However, it is important to note that the Brinell hardness test is related to the formation rock compressive strength but is not that convenient to use because the unit of hardness is dimensionless. So, BHN cannot be related to drawdown as easily as compressive strength.
Whereby this method basically means the operator is tolerating the sand production and dealing with its effect, if and when necessary. This would involves washing and cleaning of surface facilities routinely to maintain surface facility efficiency.
And that flowrate, will likely be less than the technical potential of the said well. Could be a loss in production productivity and revenue. But this figure would give us some critical information on the well flow profile.
Based on the data obtained from an exploratory well, sonic logging, and nuclear logging, we should have enough information to design the well completion to produce from reservoir or production zone that are capable to withstand the expected drawdown without entrained sand grains into the production fluid.
Plastic consolidation involves the injection of plastic resins that are attached to the formation sand grains. The resin subsequently hardens and forms a consolidated mass which binds the sand grains together at their contact points.
These resins are in liquid form when they enter the formation, and a catalyst or curing agent is then added for the resins to harden. These catalysts or curing agents can be internal or external, meaning they are either pre-mixed or send after the resin.
In both cases, the amount of resin and catalyst must be calculated and controlled for the specific well condition. And whether internal or external catalyst to be used would be dependent on the well parameter.
One of the simplest control measure is to actually control the production rate. By choosing to operate the well under a certain production parameters (drawdown, flowrate, bean opening), the sand production could be contained.
Practical approaches to Sand Control management and the nature of Sand Production and the reason for Sand control. Study in details conventional classic methods of sand control and modern methods more practical and effective to control sand and improved significantly well production such as Frac-Pack Technology and more importantlyhands on calculation of different sand control techniques in both vertical and horizontal wells by running sensitivities to determine their skin values.Get in Touch with Mechanic