Relative Permeability Measurements for Post-Waterflood Depressurisation of the Miller Field, North Sea

2000 ◽  
Author(s):  
Peter Naylor ◽  
Terrence Fishlock ◽  
David Mogford ◽  
Robert Smith
Keyword(s):  
Relative Permeability ◽  
North Sea

Field Experiences in Application of a Novel Relative Permeability Modifier Gel in North Sea Operations

2005 ◽  
Author(s):  
Jonathan James Wylde ◽  
Graham David Williams ◽  
Christian Alexander Shields
Keyword(s):  
Relative Permeability ◽  
North Sea ◽  
Field Experiences

Water Saturation Modeling Challenges in Oil-Down-to Wells: An Example from a Multidarcy North Sea Reservoir

2021 ◽  
pp. 1-15
Author(s):  
A. Larsen ◽  
F. Ahmadhadi ◽  
E. Øian
Keyword(s):  
Relative Permeability ◽  
North Sea ◽  
Water Saturation ◽  
Pore Throat ◽  
Throat Radius ◽  
Initial Water ◽  
Transition Zones ◽  
Excess Water ◽  
Height Model ◽  
Perched Aquifers

Summary The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multiphase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which affect relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modeling. Therefore, the saturation height model should not only capture an average hydrocarbon pore volume but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution. This work introduces and describes a new term, excess water, for more precise classification of saturation height model scenarios in reservoirs in which multiple mechanisms have interacted and caused a complex water saturation distribution. An example of the presence of transition zones related to drained local perched aquifers (excess water) in oil-down-to (ODT) wells is shown using a limited data set from a North Sea reservoir. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modeling of oil migration over millions of years. Highly permeable reservoirs are more likely to have locally trapped water because of lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high- and low-permeability reservoirs may have significant excess water because of ongoing dynamic effects. In both cases, long distances for water to drain laterally to a regional aquifer enhance the possibility for a dynamic excess water situation.

Using Drillstem and Production Tests To Model Reservoir Relative Permeabilities

2008 ◽  
Vol 11 (06) ◽  
pp. 1082-1088 ◽  
Author(s):  
John D. Matthews ◽  
Jonathan N. Carter ◽  
Robert W. Zimmerman
Keyword(s):  
Relative Permeability ◽  
North Sea ◽  
Water Saturation ◽  
Reservoir Management ◽  
Simulation Models ◽  
Relative Permeabilities ◽  
Use Of Data ◽  
Local Water ◽  
Water Cut ◽  
Permeability Data

Summary Relative permeabilities are fundamental to any assessment of reserves and reservoir management. When measurements on core samples are available, however, they often predict initial water production that is not experienced by individual wells. For example, dry oil production occurs from portions of reservoirs where the local water saturation is relatively high, even though the relative permeability data would predict a water cut in the range of 30 to 60%. This lack of agreement means that effective reservoir management is hampered because it is difficult for simulation models to mimic the observed reservoir production without use of data that may bear little resemblance to measurements. After a brief discussion of relative permeability, the focus of this paper is first to examine the uncertainties in the data that are used for the predictions. This then provides a numerically structured approach to adjustments that need to be made to data so that history matching of simulation models can be achieved. The relative permeabilities, rather than saturations and fluid properties, are shown to be the least certain of the relevant data. The second focus in the paper is to explore the reasons why the relative permeability data are so uncertain. The evidence points to the fact that oil emplacement and the subsequent geological history of the reservoirs have not been considered sufficiently in preparing core samples before making measurements. Greater reliance on drillstem and early production tests is, therefore, crucial for deriving reservoir relative permeabilities until laboratories are able to mimic oil emplacement within rock samples as experienced in the reservoir. The main source of data is the abandoned UK North Sea reservoir Maureen (Block 16/29a). Inevitably, during the 36 years since discovery, some data have been misplaced. Nevertheless, sufficient data exist to highlight the potential need for a paradigm shift in understanding how relative permeabilities should be obtained for reservoir simulation. Introduction There are many examples of dry oil production from portions of reservoirs where the local water saturation is relatively high (Matthews 2004). On the occasions when relative permeability data are available, predictions of the expected water cut are not zero but typically in the range of 30 to 60%. A particular example is that of the abandoned UK North Sea reservoir Maureen (Cutts 1991). This lack of agreement means that effective reservoir management is hampered because it is difficult for simulation models to mimic the observed early reservoir production without use of data that may bear little resemblance to measurements. The focus of this paper is first to examine the uncertainties in the data that are used for the predictions. The Maureen reservoir--its data were placed in the public domain for research and training purposes by Phillips after it was abandoned (Gringarten et al. 2000)--provides the main source of information. The data examined are viscosity, saturation, and relative permeability. Having established which data are the most uncertain, the paper then includes a brief discussion of the transition zone and oil emplacement to understand the nature of the uncertainties in relative permeability measurements and, in particular, measurements of the irreducible water saturation. From this, a new avenue of research related to oil emplacement can be identified that, if pursued, may lead ultimately to better reservoir-management models.

Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs

1999 ◽  
Vol 2 (04) ◽  
pp. 393-402 ◽  
Author(s):  
H.L. Chen ◽  
S.D. Wilson ◽  
T.G. Monger-McClure
Keyword(s):  
Interfacial Tension ◽  
Relative Permeability ◽  
North Sea ◽  
Flow Behavior ◽  
Water Injection ◽  
Gas Condensate ◽  
Gas Oil ◽  
Hydrocarbon Recovery ◽  
Gas Condensate Reservoirs ◽  
Gas Condensates

Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss.1,2 Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system.3,4 If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates.5 Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements.6 Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates.7,8 Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties.3,9–20 Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ dropout versus external injection or inflowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability.7,21,22 Reported blowdown experiments imply gas recovery depends upon the degree of gas expansion.7,8 The kr results obtained in this study represent gas condensate flow between the far-field and the near-wellbore region. The results are useful input for numerical simulation, especially to test rate- or IFT-sensitive relative permeability functions. Results on hydrocarbon recovery and trapping from water injection and blowdown are beneficial in evaluating improved recovery options for gas condensates. Experimental Procedures Coreflooding experiments were performed under reservoir conditions using rock and fluid samples from two distinct North Sea gas condensate reservoirs. A detailed description of the experimental methods is provided in the Appendix. Briefly, the experiments were conducted in a horizontal coreflood apparatus equipped with in-line PVT and viscosity measuring devices. The entire system experienced in-situ condensate drop out by constant volume depletion (CVD) from above Pd to either the pressure corresponding to CCS, or to the pressure of maximum condensate saturation Scmax Steady-state krg was measured by injecting equilibrated gas (before CCS). Steady-state krg and krc were measured by injecting gas condensate repressurized to above Pd (after CCS). The gas/oil fractional flow rate was defined by the pressure level in the core which was controlled by the core outlet back-pressure regulator. During krg measurements, the injection rate was varied to access rate effects. After the krg or krg and krc measurements to Scmax were completed, water injection was performed to quantify hydrocarbon trapping and recovery. Blowdown followed to evaluate additional hydrocarbon recovery. Recombined Reservoir Fluid Properties. Two North Sea gas condensate reservoir fluids were recombined using separator oil and synthetic gas. Tables 1 and 2 list compositions and PVT properties for the reconstituted fluids. The Pd was 7,070 psig at 250°F for Reservoir A, and 6,074 psig at 259°F for Reservoir B (Table 2). The maximum liquid dropout under constant composition expansion (CCE) was 31.7% for Reservoir A, and 42.5% for Reservoir B (Fig. 1). Reservoir B is a richer gas condensate and exhibits more near-critical phase behavior than Reservoir A.

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