Mixed mineral scales were observed in production tubulars of many Mobile Bay gas wells. These wells are mostly ultra-high temperature (about 400oF) sour gas producers with condensed formation water. Reservoir pressure (about 5000psi) is considered low for the 21,000 ft deep wells due to depletion. Hydrochloric and organic acids have been used historically for scale removal in these wells with mixed results.
Scale analysis of the samples retrieved from these wells confirmed the presence of salts and mineral scales. Six commercial treatment products were evaluated kinetically and thermodynamically for their dissolution efficiency on these field scale samples. One product with non-acid nature was identified to be the best to dissolve the scales efficiently with minimum operational risks of scale re-precipitation, corrosion of tubulars, and potential formation damage.
Treatment candidate wells were analyzed based on well performance evaluation. Three wells with skins significantly higher than expected due to scale formation in the production systems, were selected as treatment candidates. These wells were treated with the nitrified non-acid system to dissolve the skin damage. Treatments are considered successful with an additional gas production gain of 1,867 BEQ/day. The paper discusses the laboratory evaluation and field validation of the non-acid operationally simple system for the scale removal.
The Fairway Field is located in the Gulf of Mexico, four miles south of Dauphin Island, Alabama, and 17 miles southeast of the sour gas processing Yellowhammer plant 1,2. The Yellowhammer Plant and the Fairway Field, together make Shell's Mobile Bay Operations as illustrated in Figure 1. In 1991, first production of natural gas began from Norphlet formation of Fairway discovery from depths between 21,000 and 22,000 ft. The reservoir temperature and effective stress are about 400 oF and 70 MPa, respectively.
Four Mobile Bay wells were selected to be the candidates for matrix acidizing treatment because of their low production. The low production was suspected to be due to the formation damage caused by the scale build up possibly in the tubing and around the perforations. The scales were not quantitatively analyzed before the matrix acidizing due to the unavailability of the scale sample. However, historical well data indicate that the type of the scale should be suspected as a mixture of metal sulfides, calcium carbonate, and barium sulfate. Many hydrochloric acid jobs have been carried out on these candidate wells, but production generally decreased after treatment. Most recently, a pickling treatment followed by matrix acidizing was carried out with a chelant-based organic acid; this particular acid was selected considering the nature of the scale, corrosion inhibition rate at high temperature and minimum re-precipitation of the scale. After pickling the production tubing, the scale collected consisted mainly of Ni3S4, NiS and chromium compounds. This type of scale comes from the interaction of hydrogen sulfide and the tubing materials. After acidizing, the scale collected was analyzed to contain mainly the tubing materials and FeS2 and BaSO4. Even though post treatment production increased by 1.2 MMSCF with less draw-down compared prior to the acid treatment, the production decreased to the same rate as before in one week. The skin was not changed. This may be due to the facts that the acidizing treatment cannot dissolve the scale components such as BaSO4 and FeS2, and the wellbore is not completely clean, possibly around the perforations.
A unique single-well tracer test sequence for quantifying reservoir fluid drift rate free of dispersion is presented. Similarly with previous methods, the new method relies on the time dependence of drift. An analytical model allows the results to be interpreted using a Personal Computer at the wellsite.
Site qualification and characterization are two of the most important tasks the engineer faces prior to field application of an improved Oil Recovery (IOR) process pilot. Earlier reports (1) introduced a new single tracer test (SWTT) that uses water-soluble-only injectants that simplify test interpretation and improve residual oil saturation determination1 and (2) studied the detrimental consequences and methods of detection of pH changes on ester SWTT results. This report addresses another parameter, reservoir fluid drift rate, which is often overlooked but can be important in the design and analysis of some pilots.
In the vicinity of producing or injecting wells, fluid movement is dominated by radial pressure gradients. When these operations cease, fluid motion may continue as the result of a field-wide linear pressure gradient. The magnitude and direction of this gradient is controlled by areal voidage imbalances and natural fluid influxes. This linear motion of reservoir fluids is referred to as "drift." Fluid drift may alter the flood areal sweep pattern and should be considered in the placement of injection, sample and production wells. Optimum reservoir management may also require a detailed knowledge of fluid drift velocity
An estimate of fluid drift velocity and direction may be obtained from analysis of the known geologic properties and natural or injected water drive pressure maintenance and production histories. A somewhat more quantitative drift velocity value has historically been obtained from numerical analysis of ester-based SWTT results. In the SWTT procedure, typically run to determine waterflood remaining oil saturation, a drift velocity is used in the calculation of the oil saturation.