DOI: 10.1007/s10967-009-0513-9
Journal of Radioanalytical and Nuclear Chemistry, Vol. 280, No.2 (2009) 287–292
Enhanced oil recovery methods studied by gamma tracer scanning at simulated reservoir conditions D. Ø. Eriksen,1* O. B. Haugen, T. Bjørnstad Institute for Energy Technology, P. O.Box 40, NO-2027 Kjeller, Norway (www.ife.no) 1 Present address: Primus.inter.pares as, Kongsberggata 20, NO-0468 Oslo, Norway (Received February 17, 2009)
During recovery (production) of hydrocarbons pressure is maintained by injecting prepared sea water and recycled gas (lean gas) into dedicated injection wells. In one well at the Snorre field in the North Sea the injected gas was recycled too fast to enable support of pressure and squeezing of oil. To plug this high-permeable area the operator wanted to inject foam as a test of its possibilities to decrease gas permeability. As part of the project laboratory tests were included. In these tests we could for the first time map the foam inside the sandstone sample at simulated reservoir conditions. The tracers used were 22Na+ for the γ-scanning of the aqueous brine, tritiated water for permeability measurements, and 35S-labeled organic sulfonic acid of the same compound as the surfactant. This method resulted in a “negative” mapping of the foam, i.e. measurements of the absence or exclusion of the aqueous phase by the foam. This method was new and showed that radiotracer-based γ-scanning could give much more accurate measurements of the position of the foam than the standard method using measurements of pressure drops over parts of the core.
Introduction Oil and gas reservoirs consist of porous rock where the hydrocarbons are located in the pores and fractures. Also water brine is usually present. There is normally segregation of the fluids in such reservoirs, i.e. the light hydrocarbons (gas) on top, oil in the middle, and aqueous brine below. During recovery (production) of the hydrocarbons pressure is maintained by injecting prepared sea water and recycled gas into dedicated injection wells. In the North Sea the reservoirs are positioned 2–3 km below seabed. Therefore the temperatures and pressures vary typically over the range 80–160 °C and 250–350 bars, respectively. At the Snorre field in the North Sea operated by Saga Petroleum (present operator is StatoilHydro) a zone in a gas injector well started to experience increased permeability resulting in too high and too fast throughput of injected gas. The operator decided to try to reduce the gas permeability by injection of foam, i.e. injection of a surfactant creating a static foam phase when exposed to gas. Use of foam was at the time quite new and, in addition to the field test, comprehensive laboratory tests were conducted. As part of this program IFE performed mapping of the foam behavior under dynamic conditions by using gamma scanning and radioactively labeled tracers complimentary to standard tests using measurements of the pressure gradient along the core. Scanning gamma-ray densitometry has been applied to map foam in Boise sandstone.1 Recently, CT has been introduced as a means to map foam in rock samples.2
Foam is a mixture of a surfactant dissolved in an aqueous brine and a gas. The presence of water is imperative as the foam needs a high surface tension liquid to form. Presence of organic compounds will usually destroy the foam. Thus, to form a foam, the rock must first be saturated with water brine.
Experimental The tests were designed to enable use of the 2D gamma scanner developed at IFE. Pressures about 305 bars and temperatures at 90 °C were used. Berea sandstone was used as the porous matrix. Two cylindrical specimen, 230×26 mm each, were used as core material. They were wrapped in Al-foil to reduce diffusion of gas out of the core. Outside the metallic foil a sleeve of Vitron rubber was placed. At both ends, stainless steel connectors were attached. These connectors allowed a cross-sectional distribution of the fluids into and out of the core. The sleeve was attached to the connectors by two hose clamps on each. To avoid fluid flow along the surface of the core a surrounding water pressure of 30–60 bars was applied. The two hose clamps assured no mixing of surrounding water with fluids in the core. This was confirmed both by the flow through the core and by the flow into the surrounding volume, i.e., zero. The porosity of the core used was measured by He-porosimetry to 22.35%. The experimental set-up is shown in Fig. 1. A special Hassler cell was developed for this purpose.
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Akadémiai Kiadó, Budapest Springer, Dordrecht
D. Ø. ERIKSEN et al.: ENHANCED OIL RECOVERY METHODS STUDIED BY GAMMA TRACER SCANNING AT SIMULATED RESERVOIR CONDITIONS
Fig. 1. Experimental set-up drawn schematically. Legend: A = amplifier, BPR = back pressure regulator (release diaphragm valve), b = balance, C = controller, D = detector in lead shield, HV = high voltage, J = jack driven by step motor, LSFCD = liquid scintillation flow cell detector, P = pump, p = manometer, Pc = piston cylinder, pt = position table, ∆p = difference pressure manometer, R = fluid reservoir, SC = sample collector, V6 = six port inlet valve
The chemicals and radioactive tracers were N2 as a model gas, artificial brine of composition listed in Table 1, Surfactant – a Na-salt of C16-sulfonate labeled with 35S, tritiated water – HTO, and 22Na+. The radiochemicals were all purchased from Amersham, UK. The labeling of the sulfonate was done at IFE3 by substituting the corresponding bromide with a sulfonic group. Analysis of purity and comparison with the commercial product was performed at the University of Oslo by HPLC analysis4. Before the foam could be injected we had to prove that the core behaved according to expectations and that the surfactant (foamer) followed the aqueous phase while gas was absent. Thus, the experiment was designed both for use of pure betaemitters and of gamma-emitters separately and simultaneously. The gamma-scanner used is described by ERIKSEN et al.5 and the beta-counter used was a flowcell detector Packard Radiometric Flo-one/Beta series A-100. The outlet aqueous phase was mixed with the liquid scintillator Ultima Gold XR supplied by Packard. While the gamma-scanning could follow the brine movement dynamically along the core, the beta-emitting tracers could only be measured at the outlet. The liquid phases were also collected by a Gilson sample collector model 221 for later analyses. The flow of gas was controlled by pumping the gas from a piston cylinder
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where the cylinder was moved by injecting water by a HPLC-pump. Thus a constant and low flow of gas could be maintained. Results and discussion Figure 2 shows the 35S-labeled surfactant injected together with brine labeled with HTO and flooded through the core saturated with brine. The flooded volumes directly indicate the pore volume of the core. A previous test with a 22Na+ pulse gave a pore volume of 109.8 mL, but in the test shown in Fig. 2 we measured 106.35 and 106.7 mL for surfactant tracer and HTO, respectively. Berea sandstone is a silicate and is known to possess negatively charged surface. Thus it is natural that a negatively charged compound experiences a smaller volume and that a positively charged one does the opposite. HTO is considered the best tracer for such measurements. By applying Darcy’s law and using a water viscosity6 of 320 µNsm–2 at 89 °C permeabilities of 203 and 189 mD can be calculated from the results of the 22Na+ and HTO pulses, respectively. The presence of the surfactant may have altered the viscosity of the surfactant solution, but no measurement of the viscosity was performed.
D. Ø. ERIKSEN et al.: ENHANCED OIL RECOVERY METHODS STUDIED BY GAMMA TRACER SCANNING AT SIMULATED RESERVOIR CONDITIONS
Table 1. Composition of artificial water brine Ion Na+ K+ Ca2+ Mg2+ Sr2+ HCO3– SO42– Cl–
Compound added NaCl KCl CaCl2.6H2O MgCl2.6H2O SrCl2.6H2O NaHCO3 Na2SO4.10H2O
Mol.weight g/mole 58.44 74.55 146.8 203.1 266.4 84.0 258.02
Concentrations, mmole/L g/L 0.485 11.16 0.010 0.40 0.010 1.54 0.054 10.87 0.0001 0.02 0.002 0.20 0.039 10.06 0.624 22.11
Fig. 2. Pulse of tritiated water together with 35S-labeled surfactant (2.5%) measured at outlet by the flow-cell liquid scintillation detector
The fact that the surfactant pulse showed a movement similar to HTO and almost no tailing indicates that the surfactant used in our experiment did not absorb to the rock. This was contradictory to tests performed by the laboratory preparing the field test at Snorre. They claimed 0.5 mg surfactant per g rock was absorbed.7 The reason why we did not see any absorption may be because our surfactant was much purer than the commercial one, the Berea sandstone was not representative of the Snorre reservoir, or our surfactant was not the proper compound. The last possibility can be disregarded as the foaming power was proven during the course of experiment and since our surfactant had the same retention time on a C18-HPLC column as the commercial product. A sandstone reservoir will always have a variety of silicate rock types and it is therefore unlikely that the rock material used behaves somewhat differently from the real rock. Thus we are left with the first possibility as the most probable one. Before introducing foam to the core a test where gas displaced the water-saturated core was performed. Figure 3 shows the differential pressure over the core as
a function of time. When the gas reaches the core the pressure builds up as water is pushed out of the rock. When the gas breaks through, the pressure drop reaches maximum. Then, when passage is established, the pressure drop remains low. Two different tests with foam formation were performed. The second one was best designed and is reported here. The core was saturated with nonradioactive brine. Brine with 2% surfactant and 22Na+ was injected into the front-end of the core. Then gas was injected, but stopped for five minutes as the gas reached the core to enable formation of foam. The differential pressure (pressure drop) over the core is shown in Fig. 4 and gamma-scans as a function of time are shown in Fig. 5. These two figures show that foam was created and that it immobilized the water brine. Even when gas had reached the outlet of the core the 22Na-labeled brine was stationary. Contrary to this, substituting gas with brine led to the displacement of the pulse of 22Nalabeled brine. The pulse behaved almost ideally according to dispersion theory, but with a tail that was gradually decreased. This is shown in Fig. 6.
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D. Ø. ERIKSEN et al.: ENHANCED OIL RECOVERY METHODS STUDIED BY GAMMA TRACER SCANNING AT SIMULATED RESERVOIR CONDITIONS
Fig. 3. Variation of the differential pressure over the core during gas flooding of water-filled core
Fig. 4. Variation of the differential pressure over the core during gas flooding of water-filled core
The amounts of water replaced by gas were compared between the test made with and without surfactant present. The result was that 65% of the aqueous brine was removed from the core when
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surfactant was not present compared to 75%, i.e., 10% increase, when it was present. This may be an effect of reduced viscosity that makes the brine flow more easy.
D. Ø. ERIKSEN et al.: ENHANCED OIL RECOVERY METHODS STUDIED BY GAMMA TRACER SCANNING AT SIMULATED RESERVOIR CONDITIONS
Fig. 5. The immobility of the foam is shown, i.e., the water brine injected together with the surfactant
Fig. 6. Water brine displaces foam after gas has displaced water containing surfactant. 22Na+ is used to label the aqueous solution
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D. Ø. ERIKSEN et al.: ENHANCED OIL RECOVERY METHODS STUDIED BY GAMMA TRACER SCANNING AT SIMULATED RESERVOIR CONDITIONS
Conclusions The pore volume of the core was determined by tracer techniques. The effective pore volume was smaller than the calculated value by 8%. Permeability of the core was determined to approximately 200 mD. The absorptive properties of the surfactant on the rock material applied proved to be of minor importance. This is contradictory to earlier reports on the commercial surfactant and Snorre rock material where absorption of 0.5 mg surfactant per g rock was reported. The surfactant used in this work consisted of a pure compound whereas the commercial available one is a mixture of similar compounds. This is the most probable cause of the difference. Displacing water by gas, i.e., N2, at reservoir conditions leaves 75% of the water content as remaining water. When surfactant is present 65% of the water content is left as remaining water. Thus, a decrease of 10% of the water content is obtained by applying foam. The reason for this difference may be due to change in viscosity. When foam was generated, the water was almost immobilized, but the gas broke through. Resuming water flooding made the water injected together with the surfactant move as the initially injected pulse through the core. This indicates that the water pushes the foam nearly as a plug through the core with rather small amount of foam erosion. Foam breakdown would be indicated with a substantial broadening of the 22Na-
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records as a function of distance from the entrance as shown by ERIKSEN et al.8 The pressure drop over the core was doubled by the presence of foam. * The authors are grateful for the support from Saga Petroleum AS (presently a part of StatoilHydro AS), BP Exploration, and Research Council of Norway through their former research programme RESERVE. We also acknowledge the constructive discussions with TORE BLAKER (StatoilHydro), Dr MIN JACK THAM, and JIM MORGAN (BP Exploration) and the help in construction of the Hassler cell from KRISTIN WICKSTRØM, IFE.
References 1. A. R. KOVSCEK, T. W. PATZEK, C. J. RADKE, Chem. Eng. Sci., 50/2 (1995) 3783. 2. Q. P. NGUYEN, Dynamics of Foam in Porous Media, PhD dissertation, Technical University of Delft, 2004. 3. V. BJØRNSTAD, private communication, 1996. 4. K. MURUD, University of Oslo, private communication, 1996. 5. D. Ø. ERIKSEN, A. HAUGAN, T. BJØRNSTAD, S. G. HALVORSEN, H. J. T. TORGERSEN, O. B. HAUGEN, S. BRATHEIM, Contribution to 2 nd International Nuclear Chemistry Conference, Cancun, Mexico, 2008. 6. Value taken from Handbook of Chemistry and Physics, 64 th ed., CRC Press, Boca Raton, Florida, USA, 1983. 7. TORE BLAKER, Saga Petroleum, private communication, 1996. 8. D. Ø. ERIKSEN, A. HAUGAN, T. BJØRNSTAD, S. G. HALVORSEN, H. J. T. TORGERSEN, O. B. HAUGEN, S. BRATHEIM, Contribution at 2 nd INCC, Cancun, Mexico, 2008.
