Summary
A series of coreflood experiments with stimulation fluids [hydrochloric acid
(HCl) preflush followed by hydrochloric/hydrofluoric acids (HCl/HF) main flush
followed by amonium chloride (NH4Cl) post flush] has been conducted on a suite
of cores from several Gulf of Mexico Miocene turbidite reservoirs. Using
thin-section petrography and computer tomography (CT) scans, the samples were
characterized as more or less heterogeneous. Samples ranged from reasonably
homogeneous to highly laminated. Sample mineralogy was assessed by X–ray
diffraction (XRD). The quartz content of the cores ranged from 28 to 78%. One
core plug contains 39% clay, and the rest of the cores contained between 5 and
18%. These cores also contained between zero and 40% clinoptilolite zeolite.
All of these sands are unconsolidated and contain only detrital carbonates.
Treatment with HCl was not expected to cause core failure. The only core
failure observed occurred during HCl/HF treatment.
Acid response was assessed on the basis of permeability change and effluent
chemical analysis, which varied dramatically among the samples. Release of
particles was not observed. In the poorer-quality, more-laminated samples,
channeling with significant permeability increase was observed during HC1
treatment with little additional change during later stages of the treatment.
Selective pore enlargement with little alteration of the matrix framework was
observed in post-treatment thin sections. In more-homogeneous sand samples,
more-general acid attack was observed. Core effluent indicated carbonate
dissolution during the HCl preflush, while HCl/HF attacked alumino-silicates
and was roughly half spent during transit through the core. In the homogeneous
samples, comparison of thin sections before and after acidization revealed
near-complete (greater than 80%) dissolution of carbonate and an extensive
“cleaning” of clays and fines from the pore space.
We used a fine-scale simulator of sandstone acidizing to match the responses
observed in these experiments. The model corroborates the effects of
heterogeneities in the permeability field and in the mineral distribution on
the sandstone-acidizing process. These model results show how characterization
of fine-scale heterogeneity in sandstone can improve the design of
matrix-stimulation treatments.
Introduction
Ensuring a high production rate with high ultimate recovery is a critical
challenge in developing Gulf of Mexico deepwater turbidite reservoirs. On the
basis of extensive Gulf of Mexico experience, Shell recognized that a robust
strategy for acid stimulation would be required to deliver initial and ensure
long-term productivity. However, we were concerned that practices developed for
deltaic reservoirs on the Gulf of Mexico continental shelf would need to be
modified for turbidite reservoirs typical of the deep water.
Deepwater reservoirs can be classified according to many variables; e.g.,
geologic age, degree of compaction, mineralogy, or depositional environment.
Our goal in this study is to identify the relationships between reservoir
characteristics and effect of HF-containing acids. We approached this
experimentally by defining several lithotypes representative of the major
deepwater reservoirs in terms of mineralogy and texture. Mineralogy is defined
conventionally in terms of relative abundance of crystalline compounds as
determined by XRD and petrographic analysis. Texture is defined in terms of the
spatial arrangement of reservoir materials on several measurement scales.
Grain-size distribution in deconsolidated sand samples, degree of lamination
(existence of thin beds) evident in cores and logs, grain sorting measured in
thin sections, and 3D variation in density measured in CT scans on core plugs
are the methods we used to characterize the texture of a particular reservoir
sample. Available cores meeting this requirement yield core plugs with lengths
between 3.8 and 7.6 cm. As pointed out by Cheung and Van Arsdale (1995) and
Gdanski (1995), the sequence of chemical reactions initiated by the attack of
HF on alumino-silicate minerals is not complete in cores of this length. As a
result, we can address some aspects of reservoir response only by comparison to
other studies. We expected the high abundance of zeolite (clinoptilolite) in
some of the cores to have an impact on acid response. However, the variation in
core permeability and chemical response we observed correlated more strongly
with core texture than with zeolite abundance.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
23 October 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
8 May 2007
- Manuscript approved:
4 June 2007
- Version of record:
20 February 2008
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