souring

1. H2S Origin in Las Heras - Cerro Grande Oilfield
A case study - Addressing Reservoir Souring After Waterflooding
Presented to- Dr. Akhil Agrawal
Presented by- Bhawna & Priyanka
-(A.N. Cavallaro et. al.)

2. Introduction
• Las Heras -Cerro Grande oilfield
belongs to the main area called Las
Heras field, in Gulf of San Jorge
Basin, Santa Cruz Province –
Argentina.
• The zone of the field to study covers
an area of around 75 Km2 with 250
wells.
Figure 1: Field location
•The Bajo Barreal Formation is a geological formation
(reservoir rock) in the Golfo San Jorge
Basin of Chubut and Santa Cruz, Argentina.
•Main components of this formation are sandstones, lithic
sandstones and others
Geographical age - Middle Cretaceous Age
Figure 2 : Bajo barreal formation

3. (1997)
Initiation of waterflooding project
in a pilot well, injection rate of
140 m3/day
(After 6 months)
Conversion of remaining
injection wells from the first
project and same with the
additional 2 projects.
(Mid-2000)
Completion of the total
injection phase, reaching
approximately 6000 m3/day
distributed among 59
injection wells.
(In 2005)
Integration of 175
associated producing wells
into the waterflooding
strategy.
Waterflooding projects

4. • Initial reservoir Conditions:
– Temperature: 42 °C
– Pressure: 85 bar
• Waterflooding Process:
– Produced fluids separated in
surface facilities and mixed
with water from other areas.
– A small percentage of Rio
Senguer water added in Las
Heras 3 Plant.
– Water mixture is prepared in
Las Heras 3 Plant.
– Injection water pumped from
LH3 Plant to injection wells.
Figure 3: waterflooding process
(Rio sanguer water and
water from other area)
LH-3 plant

5. Waterflooding impacts on reservoir
• Initially, the reservoir was sweet (low H2S concentration)
• Following waterflooding, an increase in H2S concentration was observed
in several well
• By mid-2000, H2S presence was detected at producing well heads within the
water injection area
Figure 4: H2S Profile: First measurements (March 2001)

6. Operational
Response
Closure of
certain wells to
mitigate risks
Treatment of
other wells using
chemical
scavengers
Primary Concerns
Emphasis on
safety, emissions
control, and
environmental
impact.
Addressing
corrosion risks,
particularly
sulphide stress
corrosion
cracking.
Risk Mitigation
Implementing
measures to
control and
minimize the
identified
concerns.

7. Unusual scenario due to distinctive water composition.
Formation and injection waters have low salinity and not rich in sulphate ion
concentration.
Despite low salinity, the reservoir exhibited souring.
Water Composition:
• Sulphate ion range: 5.6 to 32.8 mg/l
• Chloride concentration: 12,000 to 14,000 mg/l
• SRB counts: 10³ to 105 per milliliter
Nutrients, particularly fatty acids, identified in the reservoir.
Significant variation in H2S concentration observed among different wells within
the same field.

8. Collect diverse water, gas, oil, and rock samples.
Detect VFA in production, injection, and native waters.
Map initial H2S variations in the field and design an
effective H2S monitoring plan.
To identify differences in the composition of injection/
production waters
Investigate water injection impact on H2S in producing
wells
Investigate propose gas treatment and reservoir souring
control alternatives.

9. Methodology
Collection Method
• H2S Collection Device developed at INGEIS which Includes a flow meter and two
H2S traps with flasks (AgNO3 or NaOH solution)
• Precipitated sulfide stored in polyethylene vessels
Sample Sources
• Oil and Water Samples collected from batteries, wells, and water treatment plant
Sulphur isotope Analyses
• VG 602 and Finnigan Delta–S mass spectrometers
Oil Analysis
• Total Sulfur Determination by ASTM Method
Water Analysis
• Fatty Acid Determination by HPLC chromatography
Additional Analysis
• From Cutting Samples
• Pyrite (SFe) analysis (Thin core section, X-Ray Diffraction, and SEM examination and
analyzed crystalline structure and amount in reservoir rock

10. Presentation of Results and Discussion
The possible mechanisms of reservoir souring analyzed by-
 Sulphur isotope ratio analysis
 Geology of reservoir
 Temperature range
 Presence of sulphides in reservoir rock
 Depth of reservoir
 Injection/production water characteristics
 Total sulfur content in oil.

11. Water Injection Response:
– Wells LH 175 and LH-143 exhibit no response to water injection.
– Primary recovery is the sole production mechanism.
– Analysis indicates the presence of fatty acids in native formation water.
– Lower Volatile Fatty Acid (VFA) concentration in injection water in
comparison to formation water.
Table 1: Fatty Acids concentrations in waters

12. H2S Concentration Distribution
Figure 5: H2S Profile: (May 2002) Figure 6: H2S profile (April 2004)

13. Water Cut and H2S Concentration Relationship
Figure 7: Correlation of H2S concentration (White lines) with Water Cut

14. Sulphate concentrations in production water and Water sulphate
concentration pattern in injection zone
Table 2: SO4
= (sulphate )
concentration
Figure 8: SO4
= Concentration profile

15. Sulphur Isotope Composition
SRB activity produces H2S with δ 34S values 15 ± 5 ‰ .
δ 34S values range between +8 and +11 ‰
Table 3: Sulphur isotope composition

16. Correlation of H2S with SO4
ˉconcentration (Black lines)
Examined profiles strongly indicate a link between injection processes and
souring development, despite significantly lower water sulphate
concentrations than those in seawater
Figure 9: Correlation of H2S with SO4
= concentration (Black lines

17. Abiotic Mechanisms Analysis
Some abiotic mechanisms were analyzed for souring in reservoir as following-
TSR
(Termochemical
sulphate reduction)
• TSR begins at 100-
140°C.
• In this case study-
Temperature <70
°C, wells not
deeper than 1300.
• These conditions
suggest this
mechanism is
unlikely.
Thermal maturation
• Total sulfur content
in oil is 0.23% w/w.
• Oil contribution to
H2S is ruled out
based on isotopic
values and absence
of initial gas H2S
detection.
Hydrolysis of metal
sulfides
• Very low pyrite
values (1%)
• Pyrite has a well
define crystalline
form, and derived
from igneous rocks.
• The pyrite is stable
at the reservoir
conditions and pH
of the formation
water.

18. Proposed mechanism for reservoir Souring
 In this case, the production of H2S from sulphate is limited by the reactive
present.
 Mesophilic bacteria (35-62ºC), can produce H2S from sulfate concentrations
in solution of the order of 1 mg/l.
 In this case, sulpahte in solution is the limiting reactant.
 The presence of fatty acids is factor supporting the process of SRB as a
cause of reservoir souring.
 The suggested model implies a reaction of first order, limited reagent,
closed system.
 The generated volume of H2S will be increasing as the injection system is
expanded.

19. H2S Elimination and control
• Triazine-based agents SRB reduced in
injection water
Chemical tretment
• Biocides, oxidants, or sulfide scavengers --
Effective in controlling H2S in surface but not
eliminating it.
Traditional
Squeeze
Treatments
• Lab tests with Acidithiobacillus thiooxidans for
economic and environmentally friendly gas
treatment.
Biological Filter
Development
• Team opts BCX method
• Pilot tests include the current area and
preventive treatment in a new waterflooding
project .
Field Tests
Planning

20. Conclusions
Reservoir souring is likely caused by sulfate reducing bacteria (SRB).
The reactive-limited process was an expanding issue throughout the
reservoir, with H2S peaking at 1500-2000 ppm due to low sulfate
availability.
Strong correlation observed between produced H2S, injection water
parameters, and subsequent souring.
Despite low sulfate ion concentrations, reservoir souring is significant;
expanding injection systems will escalate H2S generation.