WELL STIMULATION

Continuous Improvements in Acid

Fracturing at Lake Maracaibo

The Maraca limestone formation is a the HCl and its tendency to form sludge with a maximum pressure of approxi-
part of the Cogollo carbonate group after contacting the asphaltenic Maraca mately 10,000 psi during the acid-frac-
below Lake Maracaibo, Venezuela. oil. These matrix treatments had modest turing stages. A closed-fracture acidiz-
Acid fracturing with an organic-acid results, and the gained productivity was ing (CFA) stage then followed at 2 to
system has proved to be a pivotal com- lost after a few months of production. 4 bbl/min with approximately 220 bbl
pletion strategy for achieving higher of ungelled organic acid. Fracture gra-
productivities and increasing reserves. Acid Fracturing With dients for the wells varied from 0.78
The main challenges are the rela- Organic Acid to 0.86 psi/ft. A typical treatment pro-
tively high hydrogen sulfide (H2S) con- Acid fracturing was considered as an cedure pumped a total of 880 bbl of
tent, 280°F reservoir temperature, the alternative to stimulate Maraca wells. organic acid in four stages.
asphaltenic nature of the crude, and Not only would acid fracturing increase The treatment was staged, pump-
the long completion tubing that limits well productivity, but it also would help ing three pad stages to control leakoff,
pump rate. retain the generated conductivity for a increase etched length, and maintain
longer time period. Acid fracturing is a net pressure inside the fracture. The
Introduction stimulation technique where acid, usu- CFA stage followed the main treatment
The Maraca limestone formation is ally HCl, is injected into the reservoir at in an effort to increase generated con-
a 20- to 30-ft upper member of the fracturing pressures. As the acid flows ductivity. If the acid etching along the
Cogollo carbonate group at 15,000 to along the fracture, the fracture face fracture face is uniform, the retained
16,000 ft in the Urdaneta West field is dissolved in a nonuniform manner, conductivity after the fracture closes
below Lake Maracaibo, Venezuela. creating conductive or etched channels can be very low. In the CFA stage,
Reservoir volumes and productivity are that remain open when the fracture ungelled acid is injected at pressures
attributed mainly to matrix develop- closes. The effective fracture length is less than the fracture gradient to maxi-
ment, in contrast with the rest of the a function of the type of acid used, the mize the conductivity of the channels
Cogollo, where natural fractures play a acid reaction rate, and the fluid loss created during the acid-fracture stages
major role in well production. from the fracture into the formation. and help retain sufficient conductivity
When stimulation and development Acid fracturing was preferred to after the job.
strategy began focusing on the Maraca hydraulic fracturing because proppant After completion of this first cam-
group, a number of matrix stimula- cleanout in a sour well with CT required paign, the potential of acid fracturing
tions were performed, most using coiled operational and safety resources not yet was evident because of the 110% aver-
tubing (CT) at low pumping rates and in place. Additionally, the high conduc- age increase in productivity. It was evi-
volumes. The first few treatments used tivity of an acid-etched fracture made dent that the gained productivity was
15% hyrodochloric acid (HCl), but the acid fracturing a more attractive tech- sustainable over time even with the rela-
acid system was switched quickly to an nique if comparable fracture lengths tively high (4,000 to 6,000 psi) effective
organic acid blend (13% acetic and 9% could be achieved. closure stresses on the etched fractures.
formic) because of the high reactivity of Organic acid was selected rather Exceptions were the wells with high
than HCl to provide a more retarded asphaltene-deposition pressure that
This article, written by Assistant acid, minimize asphaltene-flocculation were damaged when the flowing bot-
Technology Editor Karen Bybee, con- potential, and provide less costly cor- tomhole pressure dropped below this
tains highlights of paper SPE 96531, rosion inhibition at 280°F. Thirteen critical pressure, resulting in asphal-
“Acid Fracturing in Lake Maracaibo: How jobs were performed with this organic tene dropout. This generated-conduc-
Continuous Improvements Kept on Raising acid blend of 13% acetic and 9% for- tivity sustainability can be attributed to
the Expectation Bar,” by B. Burgos, Shell mic acids, which has approximately the competence of the formation rock,
Venezuela S.A.; M. Buijse, SPE, Shell Intl. the same dissolving power as 8% HCl. which has a Young’s modulus in the
E&P; E. Fonseca, Shell Venezuela S.A.; The acid-fracture stages had a poly- 5 to 7×106 psi range.
and A. Milne, M. Brady, SPE, and R. acrylamide gelling agent for friction Even though the organic-acid fractur-
Olvera, Schlumberger, prepared for the reduction, retardation, and fluid-loss ing campaign was very successful, effec-
2005 SPE Annual Technical Conference control. Treatments were executed at tively doubling the reservoir production
and Exhibition, Dallas, 9–12 October. 16 to 18 bbl/min average pump rate in 2 years, computer simulations indi-

For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. The paper has not been peer reviewed.

54 JPT • JULY 2006

cated effective half-lengths of only 50 kaoline irregularly coating the lime- crosslinking is the reaction with the car-
to 100 ft, suggesting there was potential stone increase conductivity retention bonate formation. However, the pres-
for additional productivity improve- after fracture closure. If acid leakoff sure required to initiate flow after treat-
ment with a more-retarded system. is too high, the acid can be lost to the ment with polymer-based gelled-acid
Encapsulated citric acid was viewed formation through the first few feet of systems is significantly higher than that
as an alternative to achieve longer the created fracture, resulting in shorter required for surfactant-based systems.
etched length, and a full-scale trial was etched lengths. Additionally, the acid In this third acid-fracturing campaign,
performed with disappointing results. that leaks off into the formation is spent the surfactant-based system was chosen
Parellel to this effort, a new model for away from the fracture face where con- instead of a gelled acid or self-diverting
organic-acid spending was developed ductivity is generated. Separate studies crosslinked acid.
that showed that effective lengths great- were undertaken to address these key
er than 150 ft were achievable with an issues and develop a third-generation Field Results
organic-acid system. Simulation results system that could make the most of the Productivity. The new formulation
showed that for the average Maraca moderate- to higher-permeability wells. was tested in the field in new and pre-
well with 20- to 25-md permeability, viously fractured wells. After successful
fracture lengths greater than 150 ft HCl/Formic Acid. During the evolution- results on the first few wells, all the
would increase production only mar- ary process to optimize the acid sys- wells with at least 15-md permeability
ginally, but significant gains could be tem, it became clear that the two most were refractured with the new formula-
realized if fracture conductivity could important requirements were a high tion and it became the standard for all
be increased. carbonate-dissolving capacity and deep wells. A total of 13 wells was treated in
acid penetration to achieve a long etched the third campaign, eight of which were
Dissolving Power length. Another requirement was that refractures executed to increase the PI
Addition of HCl to the organic blend the acid could be inhibited adequately at and not because of significant pro-
used in the first campaign was seen downhole conditions. This led to devel- ductivity decline over time. The only
as a way to increase acid dissolving opment of a 7% HCl/11% formic acid well where the PI was not increased
power and effective conductivity with- system. Acetic acid was removed from was Well E. This well has the lowest
out sacrificing length obtained with the the blend because of incomplete spend- permeability-thickness product of the
previous system. 5% HCl was incor- ing downhole. A high carbonate-dis- group, and it is likely that the conduc-
porated into the blend and tried in solving capacity was obtained by adding tivity achieved with the first system was
three wells (two of which were refrac- 7% HCl. The HCl/formic acid blend has already close to the technical limit. The
ture treatments) to verify the potential dissolving capacity equivalent to 14% 35% average increase in productivity
to improve productivity indices (PIs) HCl at downhole conditions. A second led to record production levels in the
achieved with the original blend. From reason for adding HCl was to improve field and proved the merit of reformu-
the results of these refractures, it was conductivity in the near-wellbore part lating the acid-fracturing system.
apparent that wells with permeabilities of the fracture. The HCl was limited to
of approximately 7 md and less were 7% to avoid sludge formation on contact Pump Rate. Besides changing the acid
likely to have sufficient etched length with reservoir fluid. The formic acid and the gelling agent, higher pump
and conductivity already and were not in the blend starts spending only after rates were used in the third campaign.
candidates for retreatment unless the most of the HCl is consumed. Thus, the Pump rate was increased 30 to 50%,
original productivity had deteriorated formic acid penetrates deeper into the and this factor, in theory, also could
over time. fracture, resulting in increased etched have played a role in the higher pro-
The response from one of the refrac- length. Formic acid concentration was ductivity obtained. However, there is
tured wells validated the theory that set at 11%. Although a higher concen- not a clear and conclusive trend, and
additional gains could be achieved in tration may improve carbonate-dissolv- more field data are required to establish
moderate-permeability wells (15 md and ing capacity, the risk of calcium formate the benefit of higher pump rates.
greater) with higher effective conductiv- precipitation is increased.
ities, but this blend increased treatment Closure Pressure. Another factor that
costs, and approximately 85% of the Gelling Agent. To maximize etched- could have played a role in the higher
acetic acid was unable to react at down- fracture length, live-acid leakoff or loss PIs of the retreatments with the HCl/
hole conditions because of the buffering from the newly created fracture face formic acid system was the lower effec-
effect of the three-acid system. into the formation must be managed. tive closure stresses at the time of
The more control, the higher the fluid the refractures. On average, the effec-
Third-Generation System efficiency and the greater the amount of tive closure pressures were 1,000 psi
Three factors were identified as key live acid transported toward the fracture lower at the time of the treatments; but
for maximizing the effective conductiv- tip. A common technique to manage the for Wells G and H, the stresses were
ity of the etched fracture: dissolving live-acid leakoff is use of gelling agents. almost the same and their productivi-
power, acid-leakoff control, and pump The most common gelling agents are ties still increased.
rate. Higher dissolving power should polymer based. More recently, surfac- The data suggests that the more aggres-
increase retained conductivity if etch- tant-based self-diverting acids have been sive acid and significantly improved
ing is sufficiently heterogeneous. In the introduced. The chemistry and mecha- leakoff control provided by the new
case of the Maraca formation, natural nism of leakoff control are similar to gelling agent were the key factors that
formation heterogeneities and 1 to 2% polymer systems in that the trigger for led to higher fracture conductivities

JPT • JULY 2006 55

and production. The interpretations of equipped with permanent downhole the conductivity gained after the acid-
pressure-transient data show that the gauges. Pressure data taken during the fracturing stages, especially in the near-
retained fracture conductivities are con- treatment provide some insight into wellbore area. However, the effect of the
siderably higher than those obtained fracture development and leakoff behav- CFA stage on final productivity is not
with the previous system or that there ior. Fig. 15 in the full-length paper clear from the pressure data.
is an additional pressure drop resulting shows the downhole treating pressure
from skin that is considerably higher for for Well Q for the acid-fracturing stages Conclusions
the conventionally gelled systems. of the stimulation. There is a sudden 1. The acid-fracturing experience in
Another interesting finding after the 200-psi net pressure loss when the first the Maraca formation confirms that
evaluation of the organic and HCl/for- acid stage gets to the formation, which in many instances, significantly better
mic acid campaigns was that for most suggests a sudden significant increase in field-tailored solutions can be obtained
cases, the fluid-loss coefficient estimat- fluid loss. This net pressure-loss trend with proper laboratory testing and field
ed after the calibration tests increased decreases after that, probably caused trials of various alternatives.
after the first fracture. The fluid used by the increased viscosity of the acid 2. The equivalent pseudoradial skins
for all the tests was the same brine, and upon spending. The plot also shows achieved after acid fracturing the
the tests were performed before the that the intermediate pad stages have Maraca formation with a combination
acid treatment. Data suggest that the only a minor effect on the net pressure, of HCl and formic acid are consistently
second treatment reopened the same and while they lower the net pressure- between −5 and −7 and close to the
fracture, and the local permeability of loss trend as they enter the fracture, technical limit.
the fracture faces was increased signifi- this effect is lost rapidly once the sub- 3. Higher fracture conductivities, and
cantly by acid leakoff from the previous sequent acid stage enters the fracture. not longer fractures, were the key in the
treatment. This is a factor that would There are no downhole data available Maraca refracturing-campaign success.
make refracturing more challenging for the treatments conducted in the first 4. An optimum acid blend combines
and makes acid leakoff control even and second campaigns for comparison. a high carbonate-dissolving capacity
more relevant to avoid excessive leakoff with sufficiently deep acid penetration.
that leads to shorter etched lengths. CFA. After fracture closure, CFA fol- 5. In the Maraca wells fractured with
lowed all the treatments, injecting the HCl/formic acid system, CFA-stage
Net Pressure Behavior. Four of the ungelled acid at pressures below fractur- benefits were not evident following the
wells treated in these campaigns were ing pressures in an attempt to increase acid-fracturing stages. JPT

56 JPT • JULY 2006