Reservoir screening

The pragmatic way.

If you have read papers and books on EOR or just explaining the life of any hydrocarbon-producing field, then you should now that production stages usually encompass three phases: primary production, secondary (basically water flood), and tertiary (EOR). This is like the O&G religious way of doing things. The problem is, we also all know that waterflood leaves 35% of OIP in most cases – this is the world average. Then why is water flooding still the most common technique despite its low recovery efficiency?

The answers are numerous and complex, but one that seems to stand out and rank first in all projects is an economic one: profitability. The development decision and choice of a technology, especially waterflooding, is first dictated by how much money can be made, and how fast. This is generally measured by considering parameters such as discounted cash flow or net present value, NPV.  The issue is that a large NPV is not necessarily synonymous with a maximum recovery efficiency and, worse, it can be energetically unfavorable (Farajzadeh, 2019 a, b, c, d; van Essen, 2019; Farajzadeh, 2021). 

Considering the case of water injection, Farajzadeh et al. (2019, 2021, 2022) have shown using the exergy concept that there is a direct correlation between the CO₂ intensity of the oil production by water injection and field water cut. Above water cuts of 90%, a large fraction of the energy obtained from oil is used in handling the injected and produced water, which also leads to large amounts of CO₂ emission. In short, above 90% water-cut, the exergy to handle large volumes of water and little oil increases dramatically.

Figure 1: Unit exergy consumed, and CO2 emitted as functions of water cut for the water injection case. From Farajzadeh et al. (2021).

The authors have compared the exergy for waterflooding and polymer flooding and show that the project time-averaged energy invested to produce one barrel of oil from polymer flooding is smaller than that of the prolonged water flooding because of handling of large water volumes. In other words, considering polymer flooding (early in the life of the field) helps save money, energy and CO₂ on the long term. Also, for mature fields, a decrease of water cut below 80% can really help decrease the energy wasted and CO₂ emissions given the exponential profile of the exergy curve, as shown on Figure 1. In that case, one can see that polymer injection (when it impacts the water cut) can be beneficial to maximize oil recovery while minimizing energy wastes and CO₂ emissions.

Waterflooding is very often considered for two simple reasons: water is available almost everywhere and is relatively cheap to “process”. Considering the current average recovery factor in the world (between 30 and 40%), we can reasonably say that water injection has generally not been considered for its ability to maximize oil recovery, but rather because of its cost and simplicity. The issue is that, by considering the reservoir engineering principles and the experience from decades of hydrocarbon production (Dake, 1978; Pope, 1980; Bedrikovetsky, 1993), we know that water injection will undoubtedly end up with early field shut-in, or with the production of a couple of barrels of oil drowned in an ocean of produced water. By not investing into efficient oil recovery techniques at the beginning, we pay a higher price later in the life of the field. Higher price because it is not easy to mitigate the damages of early breakthrough or fingering once the water cut has reached high values. But with a more viscous water for instance, it is possible to greatly delay the issues linked to water production and handling while maximizing the recovery and energy use.

For future developments, it will be necessary to better balance the oil recovery and energy efficiency with profitability, for oilfield development is a long-term game, for all stakeholders. Not investing in a disciplined and technically sound approach will result in spending more money in attempting to fix a predictable problem. Because, eventually, money will be spent.

What is a good candidate for polymer injection?

• Current recovery factor (%), using the median or average (since zones in the field can have high recovery factors while other remain unswept)
• Current reservoir temperature (Celsius)
• Injection water salinity (g/L)
• Reservoir thickness (m)
• Average spacing between injectors and producers (m)
• Permeability (mD)
• Pore volume injectable per year (PVinj/year, %)
• Dykstra Parson coefficient
• Mobility ratio

Table 1 and Figure 3 show an example of plot for two extreme cases, hard and easy. This Polymer Web Ranking chart (Figure 2) allows a quick visualization of the potential of several fields.

	Good candidate for PF	Hard	Easy
Current recovery factor, %	Should be low = high oil saturation	0,55	0,05
Current temperature, C	The lower, the less expensive the chemistry	140	15
Salinity, g/L	The lower, the less expensive the chemistry	300	1
Thickness, m	The bigger, the longer the response	60	5
Spacing, m	The bigger, the longer the response	400	100
Permeability, mD	The lower, the lower the molecular weight and potential injectivity	1	2000
PV inj/year, %	The lower, the longer the response	0,01	0,2
Dykstra Parson	The lower, the more the polymer flood should be a viscosity control one	0,1	0,8
Mobility ratio	The lower, the more the polymer flood needs to be a heterogeneity control one	0,1	100

From this graph, we quickly see that the “easy candidates” (green, circle) will be located on the right side of the graph, and centered, while the difficult candidates will tend to appear on the left side of the graph (red, dashed line). This first rough ranking should help select 2 or 3 candidates for further investigations (completions, surface facilities, etc.) and fast-track the deployment of the technology to improve oil recovery.

What is a good candidate?

There is no silver bullet, but some sensible ideas. A good candidate for polymer injection is a field or reservoir which has significant volumes of bypassed oil, which is heterogeneous, and has a good injectivity. Everyone says that a pilot is not always economical, and I tend to disagree. Indeed, the judge of peace for an extension should be how much extra oil one can produce. For this reason, I believe that a good pattern is:
– a zone with high mobile oil saturation.
– a confined area or at least a zone where the connectivity between wells is well known.
– a zone with good injectivity: at least 0.15PV/year .
– if there is a conformance issue, it should be fixed upfront. I mean by this permeability contrast above 10:1.
– an area without commingled production, or where layers can be isolated.
– a zone where the geology is understood: it is always surprising to see polymer breakthrough in wells that were not supposed to be connected 🙂

There are some easy ways to rank a portfolio. For instance, it is expected that water flood efficiency decreases with increasing oil viscosity. Therefore, heavy oil reservoirs are great candidates for polymer injection (no surprise here). Conversely, all reservoirs with a high Dykstra-Parson coefficient will likely experience poor sweep efficiency during water injection and are also good candidates for polymer. Eventually, a good candidate will be a reservoir or a pattern with low recovery factor, low temperature, low salinity, high permeability, good injectivity. Out of this zone, complexity increases slowly. The remainder? Technical details.

---