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46
SOCAR ProceedingsReservoir and Petroleum Engineering
journal home page: http://proceedings.socar.az
IMPACTS OF CONDENSATE BLOCKAGE AND THE EFFECTIVENESS OF TECHNICAL SOLUTIONS TO IMPROVE WELL DELIVERABILITY
IN GAS CONDENSATE WELLS IN VIETNAM
N.M.Quy1, P.N.Trung2* 1Vietnam Petroleum Institute, Hanoi, Vietnam; 2PetroVietnam, Hanoi, Vietnam
SOCAR Proceedings No.1 (2017) 046-061
A b s t r a c t In order to study the effectiveness of several technologies to improve gas and condensate recovery, including production regime (gas rate, pressure drawdown control), well stimulation (acidizing, hydraulic fracturing), the utilization of highly deviated and horizontal wells and gas injection (gas cycling, dry gas injection), a numerical simulation model for the near-wellbore region of a production well in the Nam Con Son gas condensate field offshore Vietnam, was constructed to model the condensate banking process in the vicinity of the well-bore and its impacts on the well productivity index.
Keywords: Condensate blockage; Dew point pressure; Well productivity index; Well deliverability; Near-wellbore modeling.
© 2017 «OilGasScientificResearchProject» Institute. All rights reserved.
1. IntroductionWhen the pressure in a gas reservoir falls below
the dew point, liquid phase (condensate) starts to appear. In general, it happens mostly around the wellbore, leading to liquid dropout in the near-wellbore region. This phenomenon often results in reduced gas production due to the appearance of condensate - reducing the gas relative permeability (also known as the three-region liquid dropout). It is difficult to capture the condensate banking or condensate blockage in standard reservoir simulation models because the well blocks are typically too large to manage the pressure and saturation variations that lead to this localized effect.
In Vietnam, condensate blockage occurrs with most severity in the Nam Con Son (NCS) gas fields, which are characterized by high temperature, high pressure and high level of reservoir complexity. The field consists of multiple thin, stacked sand layers, with a large range of property variations, which leads to several limitations in production performance. To analyse the process of condensate blockage and its impacts on well performance, and to study the effectiveness of several technical
solutions to improve well deliverability, a single-well compositional simulation model was constructed using Eclipse E300 based on production data of NCS-3P well (fig.1). It is also well noted that condensate dropout might affect the temperature in the dropt out zone. However, the thermal change is small and the thermal effect might be negligible in comparison with pressure effect on liquid drop out zone in reservoir. For simplify, we have assumed the iso-thermal stage for simulating the condensate banking phenomenon in reservoir. Therefore, the study focuses on reservoir pressure and its effects on condensate banking and well productivity.
*E-mail: [email protected] http://dx.doi.org/10.5510/OGP20170100306
Fig.1. NCS-3P production performance
47
2. Simulation ModelingGrid StructureA three-dimensional hydrodynamic model was
constructed with a grid size of 20 x 20 x 4 and a cell size of 100 ft x 100 ft x 10 ft. The model volume was equal to the drainage area calculated by the production log test of well NCS-3P. For accurately and detailed simulation results, two local grid structures were defined by a cell size of 1 ft x 1 ft x 1 ft and with a distance of 10 ft from the well location. Permeability is the key unknown variable used in history matching. The main reservoir parameters are shown in table 1 and the representation of grid structure is shown in figure 2.
PVT ModelingIn modeling gas condensate reservoirs,
especially with compositional models, the choice of appropriate PVT tables is crucial, because during production fluid components change rapidly, especially in the near-wellbore region, which leads to change in fluid properties such as gravity, viscosity, volume factor and phase behavior. As a result, a PVT model using Peng-Robinson equation of state was built based on the fluid analysis results of the NCS-3P well (fig.3).
Relative permeabilityFor a multiphase reservoir, the relative
permeability curves play an important role in the simulation of flow behavior and well productivity index [1], especially for a complex gas condensate reservoir like the NCS field. The flow of gas and liquid in the near-wellbore region is highly dependent on the relative permeability changes due to condensate banking. For this simulation model, the relative permeability curves were constructed from the special core analysis data of NCS-3P well, which are shown in figure 4.
History matchingModel validation using well production data was
performed to ensure the reliability of simulation model. The main variables used for history matching were porosity, permeability, reservoir volume and amount of hydrocarbon in place. The history matching results are shown in figures 5 and 6, which indicate the reliability of the model because the best-matched simulated data is consistent with the observed data.
3. Condensate Banking Process To study the condensate banking process in the
near-wellbore region, the history-matched model was used for production forecast with a gas rate of 4.5 MMscf/d and a minimum bottom hole pressure of 800 psi.
The evolution of the oil saturation profile is shown in figure 7. It can be seen that liquid dropout occurs first at the wellbore after a short production time (3 days). A ring of condensate rapidly forms around the wellbore immediately after reservoir pressure drops below the dew point pressure. Condensate saturation at the wellbore quickly rises up to 57%. It should be noted that the maximum condensate
N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
Fig.2. Grid structure for NCS-3P well
Parameter Unit ValueAreal permeability mD 0.6Porosity % 14.795Initial reservoir pressure psia 8439Reservoir depth ft 11677Net thickness ft 40
Table 1 Reservoir parameters for NCS-3P well
LGR1
0.33693
LGR2
0.47770 0.61846 0.75923 0.9000
GasSat
S1
GasSat
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N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
Fig.4. Relative permeability for NCS-3P well
Fig.3. PVT modeling for NCS-3P well
1000
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id s
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Fig.5. History match for NCS-3P well – production rates
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Fig.6. History match for NCS-3P well – well flowing pressure
Fig.7. Oil saturation profile evolution
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SIA
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72 days 112 days 233 days 360 days
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0
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Fig.8. Saturation and relative permeability
saturation is much higher than predicted by PVT modeling (18%), which can be explained by the impact of relative permeability [2]. Moving away from the wellbore, the level of condensate banking becomes less severe. However, the ring of condensate banking develops at a relatively high speed, with the diameter of condensate dropout increased to 200 ft after 30 days and 1000 ft after 53 days.
Liquid dropout might significantly affect the mass flow and phase behavior, since the viscosity of the liquid and gaseous phases in a hydrocarbon mixture differs greatly. Below dew point pressure, the high-molecular components of condensate may cause a stationary or slow-moving liquid phase [3]. Figure 8 shows the impact of condensate banking on relative permeability. High condensate saturation within the liquid banking region reduces the gas relative permeability from 1 to less than 0.25, especially around the well bore. Consequently, the well deliverability is reduced, indicated by the decrease in gas production rate and well productivity index (fig.9). This complex multiphase flow behavior is typical in gas condensate reservoirs due to the presence of condensate blockage [4].
4. Factors Affecting The Condensate Blockage Process
A number of factors which may affect the condensate banking process are considered in this article, including the reservoir heterogeneity and the drawdown scheme.
Effects of Reservoir HeterogeneityTo evaluate the effect of heterogeneity and
anisotropy on the liquid dropout process, sensitivity scenarios have been analyzed by comparing well production performance, specifically:• Base case: homogeneous tank model where all
cells have constant horizontal permeability of 0.6 mD and vertical permeability of 0.06 mD (Kv/Kh = 0.1);
• Weak and strong heterogeneous models: two models were generated with weak and strong heterogeneity using sequential Gaussian simulation. For both cases, the geometric mean of permeability is 0.6 mD, i.e., the permeability field is a log-normal distribution with mean equal to -0.51 in the log space. Note that 0.6 mD is also the homogeneous permeability value in the base case;
• Weak and strong anisotropic models: three models with different Kv/Kh ratios of 0.05, 0.1 and 0.2, respectively.
0
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N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
WG
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52
Fig.9. Production profile
The effects of reservoir heterogeneity are shown in figure 10. It can be seen that, for a strongly heterogeneous reservoir, the radius of condensate banking is larger with higher condensate saturation and quicker condensate blockage development. A high level of liquid dropout decreases the gas relative permeability, which leads to the reduction of well deliverability. For weaker heterogeneity cases, the ring of condensate banking develops at slower rate toward the edge of the reservoir. Gas production rate also reflects the effects of reservoir heterogeneity, which in the strongly heterogeneous case can only maintain the plateau rate for about 1
year while the homogeneous reservoir can maintain the plateau rate for a longer time of about 1.5 years. Gas/condensate ratio can also show the effects of reservoir distribution on condensate banking. Strong heterogeneity leads to quicker pressure drop and liquid blockage, making the gas/condensate ratio increase more rapidly at the beginning, which indicates the condensation of heavy hydrocarbon components [5].
Effects of Production Rates To analyze the effects of production rate on liquid
dropout process, multiple simulation cases were
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3.50
3.70
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OR
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ay
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Fig.10. The effects of reservoir heterogeneity
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Kv/Kh = 0.1
Kv/Kh = 0.2
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N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
performed with the gas rate varying from 2.5 MMscf/d to 7.5 MMscf/d. The simulation results in figure 12 suggest that pressure control may strongly affect the condensate condition in the reservoir. At the highest production rate of 7.5 MMscf/d a large pressure drop occurs around the wellbore, leading to quick development of the condensate banking and reduction of the well productivity index, which can be clearly seen in higher gas/condensate ratio increment [6]. This process results in a higher volume of remaining condensate in the reservoir; cumulative condensate
production of the 7.5 MMscf/d case becomes lower than the base case of 4.5 MMscf/d after two years of production. The lowest gas rate case (2.5 MMscf/d) can maintain the single-phase condition for the longest time since the reservoir pressure only drops below dew point pressure after 4 months of production. However, the ultimate gas recovery of all cases are similar, which can be explained by the fact that the condensate banking phenomenon is inevitable regardless of the well production rate.
Fig.11. The effects of reservoir anisotropic
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Fig.12. The effects of production rates
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5. Technical Solutions to Improve Gas Condensate Well Recovery
Based on the analysis of condensate blockage and the factors affecting well deliverability, several techniques were considered in order to improve the well productivity based on the single well simulation model.
Well StimulationIn practice, well stimulation to improve
performance is often performed using hydraulic fracturing or acidizing. For the NCS simulation model, these techniques were modelled by adjusting
the skin factor from 2.7 to -2 and increasing well productivity index by 3.5 times. The effective stimulation period was estimated to be one year. The simulation result is shown in figure 13, indicating the positive effect of this technique, where the well productivity index increases 4 to 6 times compared to no well-stimulation. Even though the well productivity decreases sharply after the effective period due to the growth of condensate blockage, which in turn was due to higher pressure drop, the well stimulation’s positive effect remains after the effective period, with both gas and condensate rates being approximately 19% higher than the base case.
Fig.13. The effectiveness of well stimulation
N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
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57
Horizontal or Highly Deviated WellThe optimization of well trajectory may hold
an important role in improving the productivity of gas condensate well because it can lower the rate at which pressure decreases. While the base case is for a vertical well, sensitivity analysis was performed with horizontal and highly
deviated wells. Simulation results shown in figure 14 illustrate this method’s effectiveness for well deliverability and total recovery. However, due to the complex geological setting and unfavorable reservoir conditions such as high pressure, high temperature and water depth of the NCS field, this technique may not be applicable.
Fig.14. The effectiveness of well trajectory
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Fig.15. The effectiveness of gas cycling
Gas CyclingGas cycling on the production well was performed
with the following assumptions:• Production period: 06 months;• Well shut-in period: 01 month;• Gas reinjection period: 02 weeks.
Due to the complex conditions of the NCS field, gas cycling of the production well may not be an effective solution as shown in figure 15. Although
the well productivity index jumps after injection, it drops back to the original value shortly after the well is put back on production. This phenomenon can be explained by examining the NCS reservoir conditions. With high dew point pressure and low reservoir quality, the reservoir pressure around the wellbore almost immediately drops below dew point when the well starts production. The positive effect of this solution can only last for about 10 to 15 days.
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59
Gas injectionAnother technique which involves the injection
of dry gas through an injection well (Fig.16) was also considered with the following assumptions:• Gas injection is applied from the start of
production or after one year of production;• Gas injection rates: 3 MMscf/d and 4 MMscf/d.
The application of gas reinjection can greatly improve the condensate recovery, with the cumulative condensate production increasing from 210000 stb without injection to 400000 stb
with gas injection, which amounts to a 100% increase in condensate recovery (Fig.17). At the current reservoir condition, gas injection was not be able to keep the reservoir pressure above the dew point pressure but this solution can help to vaporize part of the liquid phase in the reservoir, thus improving the well recovery. Besides, it should be noted that the interaction between the injected gas and the heavier reservoir fluid will gradually reduce the dew point pressure, which may lead to a decrease in condensate banking and an improvement in production.
Fig.16. Gas injection scheme
N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
Injector
FloViz 2011.1
ProducerS1
GasBet
6. Conclusions
The article looks into the occurrence and development of condensate banking in the near-wellbore region of a gas - condensate well, which could be studied by near-wellbore simulation modeling. With simulation results on the process of condensate dropout around the well bore, the articles shows that there are multiple factors that can affect the condensate blockage in the NCS gas field, among which, the reservoir heterogeneity is the most important factor.
Sensitivity scenarios in order to study the effectiveness of technical solutions to improve well recovery show that with current NCS reservoir and fluid conditions it is impossible to maintain the reservoir pressure above the dew point pressure. Therefore, the field has to be operated under the impact of condensate banking after a short time of production. Several techniques to improve well recovery are investigated in this article. Well stimulation appeared to be the most effective method in terms of both production improvement and from an economical point of view.
60
References
1. G.Coskuner. Performance prediction in gas condensate reservoirs //Journal of Canadian Petroleum Technology. -1999. –Vol. 38. –No. 8. –P. 32-36.
2. T.Ahmed, J.Evans, R.Kwan, T.Vivian. Wellbore liquid blockage in gas condensate reservoirs //Paper SPE-51050-MS presented at the SPE SPE Eastern Regional Meeting held in Pittsburgh, Pennsylvania, PA, 9-11 November 1998.
3. Kh.A.Feyzullayev, I.M.Aliyev. The influence of composition of hydrocarbon mixture on condensate recovery in the development of depletion method //SOCAR Proceddings. –2014. –No. 3. –P. 71-76.
4. R.S.Barnum, F.P.Brinkman, T.W. Richardson, A.G. Spillette. Gas condensate reservoir behavior: productivity and recovery reduction due to condensation //Paper SPE-30767-MS presented at the SPE Annual Technical Conference and Exhibition held in Dallas, Texas, 22-25 October 1995.
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Fig.17. The effectiveness of gas injection
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61
Последствия образования конденсатных пробок и эффективность технических решений для улучшения
продуктивности газоконденсатных скважин во Вьетнаме
Н.М.Куи1, Ф.Н.Чунг2 1Вьетнамскийнефтянойинститут,Ханой,Вьетнам;
2ПетроВьетнам,Ханой,Вьетнам
Реферат Встатье,сцельюизученияэффективностирядатехнологийповышениягазо-икон-
денсатоотдачипласта,рассматриваетсячисленнаямодельпризабойнойзоныдобываю-щей скважинына газоконденсатномместорожденииНамКонСон (шельфВьетнама),позволяющая моделировать процесс образования конденсатного вала вблизи забояскважиныиеговлияниенакоэффициентеёпродуктивностисучетомрежимадобычи(дебит газа, регулирование перепада давления), воздействий на скважину (кислотнаяобработка, ГРП), использования сильно отклоненных и горизонтальных скважин, атакжезакачекгаза(циклическаязакачкагаза,нагнетаниесухогогаза).
Ключевые слова: образованиеконденсатныхпробок,давлениеначалаконденсации,коэффициент продуктивности скважины, продуктивность скважины, моделированиепризабойнойзоныскважины.
Kondensat tıxaclarının yaranmasının nəticələri və Vyetnamın qaz-kondensat quyularının məhsuldarlığının
yaxşılaşdırılması üçün texniki həllərin effektivliyi
N.M.Kui1, F.N.Çung2 1Vyetnam Petroleum Institute, Hanoy, Vyetnam;
2PetroVyetnam, Hanoy, Vyetnam
Xülasə
Məqalədəlayınqazvəkondensatverimliliyininartırılmasınınbirsıratexnologiyalarınınsəmərəliliyinin öyrənilməsi məqsədi ilə, Nam Kon Son (Vyetnam şelfi) qaz-kondensatyatağındakıhasilatquyusununquyudibizonasınınrəqəmsalmodelinəbaxılır.Modelquyudibiyaxınlığındakondensatvalınyaranmasıprosesinivəonunquyununhasilatrejiminin(qazındebiti,təzyiqdüşməsinintənzimlənməsi)nəzərəalınmasıiləməhsuldarlıqəmsalınatəsirini,quyuya təsirləri (turşu ilə işləmə,LHY),güclümaillivəhorizontalquyulardan istifadələri,həmçinin qaz vurmaları (tsiklik qaz vurulması, quru qazın vurulması) modelləşdirməyəimkan verir.
Açar sözlər: kondensattıxaclarınınyaranması,kondensasiyanınbaşlanğıctəzyiqi,quyununməhsuldarlıqəmsalı,quyununməhsuldarlığı,quyudibizonasınınmodelləşdirilməsi.
N.M.Quy et al / SOCAR Proceedings No.1 (2017) 046-061
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