Sand treatment using indigenously developed chemicals for vertical oil well- field case study

Introduction:
Production of formation sand with reservoir fluid is common phenomenon in many heavy oil and gas fields/wells. Sand production in a well can cause restricted production or complete loss of production due to sanding of the well bore. If production rates are high enough to carry produced sand to the surface, severe erosion of both surface and sub surface equipment may occur. It is a big challenge for an engineer to control/stop the sand production while maintaining the production of a well. There are several methods of sand control used in the petroleum industry, like gravel packing, wire wrapped screens, frac-and-pack, chemical consolidation and expandable screens etc. The sand production is due to the start of degradation of rock with the erosion of cement of the rock during production from a highly permeable reservoir. The erosion of the cement accelerated with time and degradation of rock leads to production of sand grains at surface together with sand accumulation in the well.

Sand production with reservoir fluid is a well-known problem in many parts of the world. Sand production in a well causes restricted production or complete loss of production due to sanding of well bore. There are several methods of sand control but most of the technologies require heavy hardware and tools thus making the cost of new well very high. Chemical sand consolidation can be an alternative to traditional techniques for poorly consolidated formations. The present studies are carried out to develop a suitable sand control technique for weakly consolidated oil/gas reservoirs using indigenously developed chemicals. The concept is based on the fact that water soluble polymers/chemicals have a strong tendency to adsorb on the surface of rock, thus binding the loose sand. However, the permeability of the formation is maintained by injecting oil soon after injection of chemicals. In order to develop this technology, a laboratory study was carried out to evaluate the chemicals for sand consolidation under static and dynamic conditions. The aim of this study is to assess a sandstone reservoir formation before and after sand treatment and the magnitude of the productivity enhancement and recovery increment.

Method and/or Theory:
SandAid* is primarily a chemical to increase the Maximum Sand Free Rate (MSFR) and a way to eliminate or significantly reduce fines migration. It has also shown to reduce water cut in some wells. It is not an absolute sand control solution such as a gravel pack, frac pack or expandable screen but will create an ionic attraction between the sand and fines grains and modifies the relative permeability of the formation. It will leave the formation in a water wet state. It can significantly enhance the performance of gravel packs and frac packs as well as standalone screen applications. SanaAid treatment is a matrix treatment that that will agglomerate sand grains/fines. It works by modifying the zeta potential of the anionic particles. By modifying the zeta potential to a value between 0 and -20 mV an ionic attraction is created. Because SandAid will work on any anionic substrate it will also modify the zeta potential of most fines and as such it can reduce or stop fines migration and prevent near well bore damage caused by fines. This in turn should allow better contribution from the complete interval and as such can increase the Pl and/or reduce relative drawdown pressures.

One of the major features of SandAid is that when the formation stresses change due to reservoir depletion or otherwise; SandAid can adapt to these changing reservoir conditions and will re-agglomerate. The reason for this behavior is that SandAid is not a bonding agent or a glue type substance such as a resin but creates an ionic attraction. The ionic attraction allows for the particles to have relative movement and adapt to stress changes or even re-agglomerate if a particle or particles becomes dislodged. One of the major features of SandAid is that when the formation stresses change due to reservoir depletion or otherwise; SandAid can adapt to these changing reservoir conditions and will re-agglomerate. The reason for this behavior is that SandAid is not a bonding agent or a glue type substance such as a resin but creates an ionic attraction. The ionic attraction allows for the particles to have relative movement and adapt to stress changes or even re-agglomerate it a particle or particles becomes dislodged.

Results, Observations, Conclusions:
In conclusion, the SandAid can be considered as a very successful stimulation job practically and economically for sand issues sandstone reservoirs with an increase of well flow rate. Therefore, the SandAid resin is suitable for consolidating of the Gialo oil field formations. Although it seems that this resin could be used for consolidation of other types of sands, but experiments should be conducted for each type of sands stone.

Novel/Additive Information: Based on the data above and during our observations for the subject well, we attempted to increase and decrease the frequency to determine the average pressure intake and optimal flow rate that avoids sand production. It was found that the optimum pressure intake (Pi) is approximately 700 psi which can be noticed from 0 % sand content. Furthermore, at frequency 51, the pump was running in upthrust condition with estimated downhole rate about 583.06 BPD, Water cut 0.79 % and 0.7 % sand content from wellhead fluid sample.

Keywords: Permeability, Porosity, Sand consolidation, Vertical reservoir, Nubian Sandstone Reservoir, Well Productivity and oil recovery, Open hole logs, FMI/OMI-UBI logs, Sand production, Loosely consolidated reservoirs, Formation strength, Chemical remedy, Permeability reduction.