**Peer Reviewed**

**Source**

**Journal**

**Conference**

- 12th International Conference on Multiphase Production Technology (1)
- 14th International Conference on Multiphase Production Technology (1)
- 17th International Conference on Multiphase Production Technology (1)
- Abu Dhabi International Petroleum Conference and Exhibition (1)
- Abu Dhabi International Petroleum Exhibition and Conference (4)
- Canadian International Petroleum Conference (2)
- European Petroleum Conference (1)
- SPE Annual Technical Conference and Exhibition (11)
- SPE Asia Pacific Oil and Gas Conference and Exhibition (1)
- SPE Enhanced Oil Recovery Conference (2)
- SPE EOR Conference at Oil and Gas West Asia (2)
- SPE Middle East Oil and Gas Show and Conference (1)

**Theme**

**Author**

- Abdou, Medhat K. (1)
- Al-Ajmi, Moudi (1)
- Azeem, J. (1)
- Azeem, Jawad (4)
- Bartolome, P. (1)
- Basioni, Mahmoud Ali (1)
- Bjurstrøm, Kersti E. (2)
- Boesen, Rasmus Risum (1)
- Bylov, M. (1)
- Christensen, P.L. (1)
- Christensen, Peter Lindskou (1)
- Downs, J.D. (1)
- Fadnes, F.H. (1)
- Fredenslund, A. (1)
- Gibson, Adrian P. (1)
- Gohary, M. E. (1)
- Gurdial, Gurdev S. (1)
- Hasdbjerg, Casper (1)
- Hjermstad, Hans Petter (3)
- Holst, A. (1)
- Hustad, Odd Steve (2)
- Izwan, Hairul (1)
- Jakobsen, T. (1)
- Jia, Na (2)
- Krejbjerg, K. (1)
- Krejbjerg, Kristian (3)
- Kumar, A. (1)
- Larsen, Jarle (1)
- Leekumjorn, Sukit (3)
- Lindeloff, N. (3)
- Meisingset, Knut Kristian (1)
- Memon, Afzal (1)
- Memon, Afzal I. (1)
- Michelsen, Michael L. (2)
- Milter, J. (5)
- Munck, Jan (1)
- Negahban, Shahin (1)
- Pedersen, K. S (1)
- Pedersen, K. Schou (2)
- Pedersen, K.S. (8)
- Pedersen, Karen S. (1)
- Pedersen, Karen Schou (8)
- Pottayil, A. (1)
- Ramli, Mohd Fadli (1)
- Rasmussen, Claus P. (2)
- Rasmussen, Claus Patuel (2)
- Rasmussen, Peter (1)
- Ronningsen, H.P. (2)
- Sah, Pashupati (4)
- Schou Pedersen, Karen (7)
- Sener, Ilhan (1)
- Shaikh, Jawad Azeem (2)
- Skjold-Jorgensen, Steen (1)
- Sonne, J. (1)
- Sorensen, Henrik (2)
- Sømme, B.F. (1)
- Sørensen, H. (3)
- Sørensen, Henrik (1)
- Thomassen, P. (1)
- Tybjerg, P. (1)
- Tybjerg, Peter (1)
- Tybjerg, Peter Christian (1)
- Yang, Tao (1)

**Concept Tag**

- adjustment (2)
- application (2)
- Artificial Intelligence (2)
- asphaltene (3)
- asphaltene inhibition (4)
- Asphaltene Onset (3)
- Asphaltene Precipitation (3)
- asphaltene remediation (4)
- bar (4)
- calculation (4)
- carbon number fraction (4)
- characterization (2)
- characterization procedure (2)
- co 2 (2)
- coefficient (8)
- complex reservoir (2)
- component (14)
- composition (16)
- compositional gradient (2)
- compositional variation (2)
- Compound (2)
- compressibility (2)
- concentration (3)
- condensate (5)
- condensate reservoir (2)
- contact (2)
- correction (3)
- correlation (6)
- corresponding state (3)
- corresponding state model (2)
- corresponding state viscosity model (2)
- critical point (3)
- cubic equation (4)
- Drillstem Testing (2)
- drillstem/well testing (2)
- enhanced recovery (2)
- enthalpy (3)
- eos (2)
- EOS model (3)
- equation (8)
- equation of state (18)
- equilibrium (6)
- experiment (7)
- factor (3)
- flow assurance (3)
- fluid modeling (18)
- formation (3)
- fraction (9)
- gas (3)
- gas Condensate (4)
- gas hydrate (2)
- gas injection (5)
- GOR (2)
- gradient (3)
- heat (2)
- heavy oil (3)
- high pressure (2)
- hydrate (3)
- hydrate formation (2)
- hydrate inhibition (4)
- Hydrate Remediation (4)
- hydrocarbon (6)
- injection (9)
- injection gas (6)
- Methanol (2)
- mixture (8)
- MMP (2)
- model (4)
- mole (4)
- molecular weight (5)
- MPa (2)
- Oil Viscosity (3)
- oilfield chemistry (6)
- paraffin remediation (4)
- pc-saft equation (3)
- Pedersen (9)
- Peneloux (2)
- Phase Behavior (2)
- Production Chemistry (6)
- PVT data (2)
- PVT measurement (18)
- remediation of hydrates (4)
- reservoir (9)
- reservoir description and dynamics (16)
- reservoir fluid (17)
- reservoir pressure (4)
- reservoir simulation (4)
- Reservoir Surveillance (2)
- saturation (10)
- saturation point (6)
- saturation pressure (4)
- scale inhibition (4)
- scale remediation (4)
- Simulation (9)
- SPE (2)
- Upstream Oil & Gas (35)
- viscosity (5)
- water (4)
- wax inhibition (4)
- wax remediation (4)

Boesen, Rasmus Risum (Calsep A/S) | Sørensen, Henrik (Calsep A/S) | Pedersen, Karen Schou (Calsep A/S)

Asphaltene data for 36 reservoir fluids from different geographical regions has been used to evaluate and compare the ability of four commonly used screening methods and three equations of state to identify fluids likely to present asphaltene problems during production. The screening methods are the de Boer method and three SARA based methods. The data covers asphaltene onset pressure data with and without gas injection at a wide range of temperatures. The evaluation showed that the Asphaltene Stability Index method is the most reliable of the tested screening methods, but all screening methods may fail to identify fluids with asphaltene problems. Analyzing asphaltene onset pressure data, it was seen that fluids precipitating asphaltenes by depressurization consistently seem to be causing asphaltene problems during production. The three equations of state tested were the SRK equation, the CPA equation and the PC-SAFT equation. None of the equations was able to predict asphaltene onset pressures in the absence of measured data, but all three equations could be tuned to match the development in asphaltene onset pressure with temperature and the impact of gas injection on the asphaltene onset pressure. The more complex CPA and PC-SAFT equations showed no advantage over a classical cubic equation of state. A newly developed algorithm for generating complete asphaltene phase diagrams helped explain why different trends in asphaltene onset pressure with temperature may be observed.

AOP, asphaltene, asphaltene inhibition, Asphaltene Onset, asphaltene onset pressure, Asphaltene Precipitation, asphaltene problem, asphaltene pt, asphaltene remediation, equation, gas injection, hydrate inhibition, Hydrate Remediation, injection, oilfield chemistry, paraffin remediation, phase diagram, Production Chemistry, remediation of hydrates, reservoir, reservoir fluid, reservoir temperature, scale inhibition, scale remediation, screening method, Upstream Oil & Gas, wax inhibition, wax remediation

Country:

- Asia > Middle East (0.70)
- North America > United States (0.69)

Oilfield Places:

- South America > Venezuela > Anzoategui state > Oficina Area > Eastern Venezuela Basin > Mulata Field (0.99)
- North America > United States > Gulf of Mexico (0.98)
- Asia > Middle East > Kuwait (0.89)

Tybjerg, Peter (Calsep A/S) | Pedersen, Karen S. (Calsep A/S) | Pedersen, K. Schou (Calsep A/S)

A C_{7+} characterization procedure reservoir oil mixtures is presented for the PC-SAFT equation of state. The plus fraction of a reservoir fluid composition is split into carbon number fractions and the PNA distribution estimated of each C_{7+} carbon number fraction. For each component class (P, N, and A) a constant ε parameter is used independent of molecular weight while the parameter m is assumed to increase linearly with molecular weight. The m and ε parameters of the individual component classes are combined into one value, representative of the whole carbon number fraction. To ensure reliable density predictions, the parameter

bubble 1, carbon number fraction, characterization procedure, composition, condensate, critical point, cubic equation, equation, equation of state, fluid modeling, fraction, molecular weight, oil mixture, pc-saft equation, pc-saft parameter, Pedersen, PVT measurement, reservoir fluid, saturation, saturation pressure, Upstream Oil & Gas

Industry:

- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)

The paper describes how the reservoir temperature can be simulated from well test data. The procedure is exemplified using data for four different reservoir fluids, one gas condensate, one oil mixture, and two volatile oils. The reservoir pressures vary from 150 to 800 bar and the reservoir temperatures are in the range of 70 - 130^{o}C. The procedure requires knowledge of the reservoir pressure and it is a further requirement that well test pressure and temperature data at bottom-hole conditions exists for a fixed flow rate and a period long enough to have a negligible heat exchange with the surroundings. The well test data reveals that the temperature of the gas condensate will decrease when expanded in the near well bore area, while a temperature increase is seen for the oil mixtures. With negligible heat exchange between the flowing fluid and the surroundings, the flow process can be regarded an adiabatic expansion of the reservoir fluid from reservoir to bottom-hole conditions. The enthalpy at reservoir conditions is found from a Pressure-Temperature flash at bottom-hole conditions corrected for a possible height difference between bottom-hole and perforation interval. The reservoir temperature is found from a subsequent Pressure-Enthalpy calculation at reservoir pressure. The thermal calculations are carried out using a cubic equation of state. The simulated reservoir temperatures are in good agreement with the data material.

bottom-hole condition, bottom-hole pressure, coefficient, Drillstem Testing, drillstem/well testing, enthalpy, equation, flow period, joule-thomson coefficient, JT coefficient, kinetic energy, perforation interval, potential energy, reservoir, reservoir fluid, reservoir pressure, reservoir temperature, saturation, Temperature Effect, temperature measurement, Upstream Oil & Gas

SPE Disciplines: Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)

Gas injection is a recognized enhanced recovery technique for oil reservoirs, but has been given less attention for gas condensate fields. If a gas condensate is produced by natural depletion, the condensate-gas ratio of the produced well stream will steadily decrease after the saturation pressure is reached. The liquid condensed will stay back in the reservoir and will not be produced.

A laboratory study was conducted for a Middle East gas condensate reservoir fluid. Three different injection gases were used- N_{2}, CO_{2} and a lean hydrocarbon gas. A gas revaporization experiment was conducted with each gas on the depleted reservoir fluid. The gas revaporization experiments showed that injection of CO_{2} made the liquid dropout in the PVT cell decrease substantially. Already condensed liquid was revaporized and led to an increased liquid content in the released gas. In small concentrations N_{2} made the liquid dropout increase, but with a continued injection of N_{2} the amount of liquid dropout declined. The hydrocarbon gas made the liquid dropout decrease at all concentrations, but to a lesser extent than CO_{2}. An analysis of the results showed that injection of CO_{2} and a lean hydrocarbon gas may substantially increase the liquid recovery from the actual field, while it is questionable whether N_{2} injection will have much impact on the liquid recovery.

co 2, complex reservoir, composition, condensate reservoir, enhanced recovery, equation of state, experiment, fluid modeling, gas Condensate, gas injection method, gas revaporization, gas revaporization experiment, hydrocarbon, injection gas, liquid recovery, PVT measurement, reservoir fluid, revaporization, saturation pressure, Upstream Oil & Gas

SPE Disciplines:

- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)

Compositional data for reservoir fluids sampled in various depths in five different North Sea reservoirs is presented and analyzed. All five reservoirs have a gas-oil contact and for each reservoir one composition exists from above and two or more from below the gas-oil contact. For all reservoirs the compositional gradient is higher than can be explained by gravity segregation alone. The highest compositional gradient is seen for a reservoir, which is rich in asphaltenes. The compositional variation with depth is modeled using the Haase model, which expresses the influence of a temperature gradient in terms of the specific enthalpies of each fluid component. The high compositional variation seen for the asphaltenic reservoir fluid suggests that the condensed aromatic compounds, which are the main constituents of asphaltenes, have a significantly higher absolute specific ideal gas enthalpy than paraffinic and naphthenic compounds.

SPE Disciplines: Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.73)

Compositional data for reservoir fluids sampled in various depths in five different North Sea reservoirs is presented and analyzed. All five reservoirs have a gas-oil contact and for each reservoir one composition exists from above and two or more from below the gas-oil contact. For all reservoirs the compositional gradient is higher than can be explained by gravity segregation alone. The highest compositional gradient is seen for a reservoir, which is rich in asphaltenes. The compositional variation with depth is modeled using the Haase model, which expresses the influence of a temperature gradient in terms of the specific enthalpies of each fluid component. The high compositional variation seen for the asphaltenic reservoir fluid suggests that the condensed aromatic compounds, which are the main constituents of asphaltenes, have a significantly higher absolute specific ideal gas enthalpy than paraffinic and naphthenic compounds.

SPE Disciplines: Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)

The paper presents field observations for wax deposition in a North Sea reservoir. Wax deposition was observed in two wells while no wax deposition was seen in other wells in the same field. To understand the underlying mechanisms 18 different production scenarios were simulated using a fully compositional wax deposition simulator. The wax deposition was modeled as a molecular diffusion process taking into account the effects of flow regime, adiabatic expansion, solubility effects and heat exchange with the surroundings. The fluid model was configured to match the measured wax appearance temperature and wax content data for the fluid flowing. The simulated pressure and temperature profiles in the well were validated against PLT data to ensure an optimum starting point for the study. The 18 production scenarios had varying GORs, water cuts and oil production rates. The simulations allowed conclusions to be drawn about the influence of GOR, flow rate and water cut on wax deposition. The two wells with deposition were flowing at lower rate than the wells with no deposition and this was found to be the main reason for the wax deposition in those two wells. At optimum operating conditions it is possible to suppress the wax deposition whereas wax at other conditions is deposited in an amount that eventually might cause plugging of the wells.

**Introduction**

bhr group 2015, coefficient, composition, deposition, diffusion, equation of state, flow rate, fluid modeling, GOR, layer thickness, multiphase 17, oil rate, Oil Viscosity, Pedersen, production control, production logging, production monitoring, Reservoir Surveillance, Simulation, sm 3, temperature profile, Thickness, Upstream Oil & Gas, viscosity, water cut

Hustad, Odd Steve (Statoil ASA/NTNU) | Jia, Na (Schlumberger DBR Technology Center) | Pedersen, Karen Schou (Calsep A/S) | Memon, Afzal (Schlumberger) | Leekumjorn, Sukit (Calsep Inc.)

This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include: - Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. - Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. - Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations. The data were modeled with the volume-corrected Soave-Redlich- Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen. Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.

SPE Disciplines: Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)

This paper presents high pressure PVT measurements and equation-of-state (EoS) modeling results for a GoM oil and for the oil mixed with nitrogen in various concentrations. The data includes:

1. Upper and lower asphaltene onset pressures and bubble point pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F) asphaltene precipitation is seen after addition of 27 mole % of nitrogen.

2. Viscosity data for the swelled fluids showing that addition of nitrogen significantly reduces the oil viscosity.

3. Slim tube runs indicating that the minimum miscibility pressure of the oil with nitrogen is significantly higher than estimated from published correlations.

The data has been modeled using the volume corrected Soave-Redlich-Kwong (SRK) and the Perturbed-Chain Statistical Association Fluid Theory (PC-SAFT) EoS. While both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid phase compressibility of the reservoir fluid swelled with nitrogen.

Nitrogen gas flooding is expected to have a positive impact on oil recovery due to its favorable oil viscosity reduction and phase behavior effects.

Oilfield Places: North America > United States > Gulf of Mexico > Green Canyon > East Gulf Coast Tertiary Basin > Block 562 > K2 Field (0.99)

SPE Disciplines: Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)

The paper presents a C7+ characterization procedure for the PC-SAFT equation of state. The characterization procedure was applied to model both routine and EOR PVT for a Middle East reservoir fluid. The injection gas contained 60 mole% of CO2. No other parameter adjustment was needed than to determine the optimum binary interaction parameters for CO2. Among the data matched was a liquid-liquid critical point on a swelling curve for a CO2 mol% of 43. The PC-SAFT simulation results suggest that the fluid for this CO2 concentration has two critical points. The one at the lower temperature agrees with the critical point found in the swelling test. The study shows that the potential of the PC-SAFT equation of state in the oil industry is not limited to modeling of asphaltene precipitation and other specialized applications. Extensive routine and EOR PVT data including a minimum miscibility pressure has been modeled using the PC-SAFT equation. Unlike cubic equations, a volume correction does not have to be applied to match liquid densities.

SPE Disciplines: Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)

Thank you!