still significant increase in condensate production (right). Two other nearby gas wells were also treated with the retarded emulsion and experi - enced similar production increases.
Although acid-oil emulsions have been employed for many years, additional focus on the details of the technique has yielded significant
Slurry Reactor Tests
10
2 3 4 5 6 7 8 9
1 0
January 1996
July 1996
January 1997
July 1997
January 1998
> Smackover well production history. Gas and condensate production from this well declined steadily over time reaching levels of 3.4 MMcf/d [96,200 m3/d] of gas and 150 bbl/d [23.8 m3/d] of condensate in August 1997, immediately before treatment. After treatment with an acid-oil emulsion, gas production increased to more than 9 MMcf/d [255,000 m3/d] while condensate rose to 200 bbl/d [31.7 m3/d]. Six months after treatment, gas production had fallen off somewhat but was still more than twice the value prior to treatment. In the same time period, condensate production fell slightly but retained most of the treatment-related production increase.
Gas Condensate Emulsified-acid treatment
450 500
100 150 200 250 300 350 400
50 0
Reservoir Coreflood Tests
Radial-Flow Simulations
> Reaction simulations in sandstone. Virtual Lab software is a prediction system that determines optimal acidizing parameters for sandstone treatment. This semiempirical system is based on laboratory data taken from samples of the formation being considered for treatment. In the first step, slurry reactor tests are carried out using acid and crushed solids (top). Analysis of effluent solutions allows determination of reaction kinetics and identification of precipitates. In the second step, coreflood tests determine permeability and porosity at reservoir conditions (middle). In the final step, all the data are combined with radial-flow simulations to determine the best acidizing treatment (bottom).
improvements. A case in point is their use in treating a group of deep, high-temperature wells in the Middle East. These wells are located in eastern Saudi Arabia and produce nonassociated sour gas at a depth of about 3,500 m [11,500 ft]. The producing zone lies in the Khuff formation and is composed of dolomite layers intermingled with limestone. Bottomhole temper atures are in the range of 127° to 135°C [260° to 275°F]. Stimulation efforts have been conducted on a regular basis by the operator to enhance perme - ability and remove drilling mud damage. Both straight HCl and acid-in-diesel emulsions have been used for stimulation of gas wells in this formation with varying results. HCl is an effective stimulation agent but is highly corrosive at the higher temperatures encountered in these wells. An acid-oil emulsion was found to be effective in providing stimulation without corrosion, but field application showed the need for optimization of the emulsifier formulation.19
Work to improve the
emulsifier was concentrated on two areas— reduced quantities and improved field operations. Earlier field tests of acid-in-diesel emulsions to stimulate wells in the Khuff formation used 28% by weight HCl in a 30% by volume acid and 70% by volume diesel emulsion. The emulsifier was a cocoalkylamine at 0.08 to 0.11 m3 [0.48 to 0.71 bbl] per 3.78-m3 [23.8-bbl] emulsion loading.20
The field application showed that although the emulsion was effective at stimulating production, further improvements
were needed. Emulsifier loadings were high, and the emulsion often broke at ambient conditions in the field, necessitating remixing and quality control in the field before use. Both of these cocoalkylamine emulsifier attributes meant longer operation times and higher cost. The operator, therefore, embarked on a program to develop and test an improved emulsion for use in stimulating the deep, high- temperature gas wells in this formation.21
Results
from laboratory testing of more than 10 different emulsifiers showed that beef-tallow amine acetate would be more effective than the coco alkyla mine formu lation.22
This new emulsifier could be used at 25% of the previous loading to make stable emulsions with no remixing at both ambient field conditions and high temperatures. In a four-well pilot campaign, the new tallow amine emulsifier was successfully employed. Mixing times in the field were reduced by 25% and poststimulation production rates exceeded expectations. Acid-in-oil emulsions are not the only option for hot carbonate well stimulation; chelants can also be used successfully, as illustrated by a well in a Middle Eastern carbonate reservoir.23
After
completion, the well was not flowing, and drilling mud filtrate damage in the formation was suspected. Despite the need to stimulate the well to start production flow, the operator had concerns about the high bottomhole temperature—110°C [230°F]—and the formation lithology at a measured depth of 2,620 m [8,600 ft]. At this
Winter 2008/2009
59
Gas production, MMcf/d
Condensate production, bbl/d
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