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Flow Assurance Study on Offshore Marginal Oil Field Development in Vietnam: The Case of Ca Ngu Vang Oil Field

Nguyen Van Tinh, Nguyen Thi Hai Yen, Trinh Tien Thang, Tong Canh Son, Le Dinh Hoe

Inżynieria Mineralna

2020

no. 2, vol. 1

15--22

Over the last few years, PetroVietnam has discovered and exploited several marginal oil fields such as Ca Ngu Vang, Te Giac Trang, Hai Su Den, Hai Su Trang, etc. however the reserves are modest. Test results received during drilling exploratory wells within these fields indicated that the maximum total daily production rate from the wells could promisingly range to about 20,000 barrels of oil per day (BOPD). Unfortunately, the optimum development of these offshore oil fields still offers numerous challenges to oil engineers due to the limitations of equipment and technology. Oil production activities worldwide show that if the daily production of an offshore oilfield is less than 20,000 BOPD, a connection of the marginal fields to their nearest larger oil field should be taken into consideration in order to efficaciously recover more crude oil. Often, this method of production requires a long subsea pipeline system. Besides, the transportation of the fluids from these fields to the processing platform will undergo several serious problems caused by the deposition of wax. All these matters should be handled to guarantee the performance of transportation. A number of models using PIPESIM, PIPEPHRASE and OLGA have been applied to design and examine the operations of the subsea pipeline in different working conditions. Results of the simulations proposed the use of passive insulation to economically eliminate wax deposition and recommended proper pipeline shutdown operations to minimize several problems related to flow assurance issues in the region of interest.

W ciągu ostatnich kilku lat w Vietnamie odkryto i eksploatowano kilka marginalnych pól naftowych, takich jak Ca Ngu Vang, Te Giac Trang, Hai Su Den, Hai Su Trang, itd.… Jednak zasoby są skromne. Wyniki testów otrzymane podczas wiercenia odwiertów poszukiwawczych na tych polach wykazały, że maksymalny całkowity dzienny poziom wydobycia z odwiertów może potencjalnie sięgać około 20 000 baryłek ropy dziennie (BOPD). Niestety, optymalny rozwój tych przybrzeżnych pól naftowych nadal stwarza liczne wyzwania dla inżynierów naftowych ze względu na ograniczenia sprzętu i technologii. Działalność wydobywcza ropy naftowej na całym świecie pokazuje, że jeśli dzienna produkcja morskiego pola naftowego jest mniejsza niż 20 000 BOPD, należy wziąć pod uwagę połączenie pól marginalnych z ich najbliższym większym polem naftowym, aby efektywnie odzyskać więcej ropy. Często ta metoda produkcji wymaga długiego systemu rurociągów podmorskich. Poza tym transport płynów z tych pól na platformę obróbkową będzie wiązał się z kilkoma poważnymi problemami spowodowanymi osadzaniem się wosku. Wszystkie te sprawy powinny być załatwione, aby zagwarantować wykonanie transportu. Szereg modeli wykorzystujących PIPESIM, PIPEPHRASE i OLGA zostało zastosowanych do projektowania i badania działania rurociągu podmorskiego w różnych warunkach pracy. W wynikach symulacji zaproponowano zastosowanie izolacji pasywnej w celu ekonomicznego wyeliminowania osadzania się wosku oraz zalecono prawidłowe operacje wyłączania rurociągu, aby zminimalizować kilka problemów związanych z kwestiami zapewnienia przepływu w obszarze zainteresowania.

Quantifying the uncertainty in the ultimate recoverable oil reserves using the Monte Carlo simulation techniques from ‘OWA’ Marginal Field, Onshore Niger Delta, Nigeria

Adeigbe O. C., Odedere I. F., Amodu O. I.

Geology, Geophysics and Environment

2018

Vol. 44, no. 4

401--412

A review on the development of marginal oil fields in Nigeria has now become an important strategic issue if it is to remain amongst the top producers in the global market, and these fields are vast, available all over the Niger Delta. One of the factors that makes a field marginal is the size of its reserves. Stochastic estimation gives a certainty in terms of the possible number of outcomes within the range of input parameters. In this work, four (4) deviated wells and 3D seismic volume (362 inlines and 401 traces) were interpreted for the evaluation of the field. The petrophysical evaluations were interpreted using the Power Log software and the Seismic, Geographix and Petrel softwares. Stochastic reserve estimation was done using Monte Carlo sampling techniques and subjected to uncertainty quantification using the Crystal Ball software by varying distributions and measuring sensitivity impact on the overall reserves. The production profile was predicted based on some assumptions and history matching which result in the overall Expected Ultimate Recovery (EUR). The petrophysical analysis shows the reservoirs to be within the unconsolidated continental Benin Formation denoted as ‘Intra-Benin’ sands, an unconventional reservoir as supposed the normal reservoir rocks within the Agbada Formation. This indicated high porosity (0.28), water resistivity (7 Ω∙m), and water saturation and also inferred Heavy Oil (low API). Nine hydrocarbon sands were identified but only three (B1, D and E), representing shallow, mid and deep reservoirs were further evaluated. 1P and 2P reserve estimates were 4.8 MMBO and 5.7 MMBO for B1; 15.2 MMMscf and 16.4 MMMscf for D; 8.4 MMMscf and 8.8 MMMscf for E respectively. The Monte Carlo simulation of 1,000,000 trials with mainly triangular distribution assumption generated P10, P50, P90 were 6.5 MMBO, 5.6 MMBO and 4.4 MMBO for B1; 17.5 MMMscf, 13.7 MMMscf and 10.8 MMMscf for D; 10.4 MMMscf, 8 MMMscf and 6.1 MMMscf for E respectively. The sensitivity impact of the input parameters were estimated and ranked, and the coefficient of variability ranges within 15% to 20% for the reservoirs indicating that there is a very low level uncertainty of reserve estimation around the P10, P50 and P90 percentiles which could be positive for investment decisions. ‘OWA’ marginal field reflects a typical low reserve (EUR) category found within the Niger Delta basin.