Hello Moustafa, your question leaves me with dread since it borders on your thesis. But you should have performed the feasibility studies on the reservoir before developing the technique. The challenge to EOR lies in the complex interaction of injected agents with the existing reservoir fluids in an ever-changing down hole environment. The difficulty is ensuring the proper chemical interaction and subsequent flow conformance of the EOR sweep front to recover more oil, more quickly. Making the right parametric decisions regarding a chosen EOR technique, while evaluating dynamic economic conditions, compounds these complex challenges. Compatibility of the technique with reservoir is essential to evaluating, modeling, and simulating various EOR methods to determine feasibility. If you have not applied your technique yet, then do. Afterwards, remodel if there are compatibility issues. I understand the money, time and energy spent. But you will be happy and satisfied in the end. Trust me. Cheers!

This is a very open question, it can be useful to clarify whether you are interested in economical /project management aspects or purely EOR aspects.

The way I would structure the issue is related to whether the EOR method is implemented in a marginal (tertiary) manner or upfront.

For tertiary implementations in most cases an inadequate selection of the EOR method will lead to at worst moderate levels of wasted investments and damage. Wasted (or even negative return) investments will correspond to the case in which the delayed gains are found after a while not being real (e.g. late switch from WI to WAG not performing due to a poor appreciation of say triphasic Kr). Early interuption with limited well damage might correspond to cases in which it is apparent that EOR is subperforming from start of the switch to EOR (e.g. polymer injectivity losses way above the expected level motivating abandonment of polymer injection). Most O&G operators will have an implementation plan in place not to put all eggs in same basket and would catch such occurence (even if they failed in the assesmesment of the adequacy of the method in the first place). In such cases, the damage might be significant at the EOR perimeter project but not so large on the baseline.

Things are more likely to worsen when EOR is considered upfront, which by the way is commonly necessary for EOR methods to fully leverage their potential. In such cases the damage is more likely to be substantial because the impact on facilities is likely to be larger (higher CAPEX stakes) and the ability of the operator to cope with unplanned behavior more limited. A failure in the domain will breach trust between business and technical staff involved with major consequences in operations and many cascading impact.

Field and project size is also of essence, large fields are better suited to phasing than small fields and tend to be produced more slowly. Therefore EOR screening and performance prediction have larger impact on smaller fields than big ones.

A few years ago, our company performed a pilot test of immiscible gas injection (in WAG mode) in a mature, waterflooded, light-oil, sandstone reservoir. The injection gas was of high CO2 content and was available as production gas with no sales value from a nearby field.

Conventional EOR method screening criteria anticipated that this was not a case for a very good “match” between EOR process and reservoir/fluid characteristics: immiscible CO2 injection has been successful in steeply dipping reservoirs or in medium-viscosity oils, at relatively high remaining oil saturations.

Our case, in contrast, is a light oil (thus with very small margin for viscosity reduction by the CO2), contained in a horizontal reservoir with a relatively high recovery factor by primary recovery and waterflooding. Besides, permeability is highest at the topo layers and lower towards deeper intervals, a configuration that favors good vertical efficiency by water but not by gas injection.

How was then decided to explore the feasibility of this process in this reservoir? The oilfield to which this reservoir belongs was one of the company’s largest assets at that time; even a small increase in recovery factor meant a very interesting volume of oil. The low remaining oil saturation was considered to have a potential for further reduction with this process, based on very conclusive laboratory tests and pilot – scale simulation studies. Injection gas was readily available for the pilot and another large source of almost pure CO2 was present in a nearby structure and would have been used for commercial expansion. On the other hand, chemical EOR and high-pressure air injection had been considered for this field and discarded for non-technical reasons such as complexity, logistics, costs, operational risk.

We proceeded to the pilot test, after stating very clearly to management that it was a risky process. After about 1,5 years of operation, with 40% pore volume of gas and water injected into two different (separate) pilot patterns, the project was abandoned because the incremental oil was much smaller than predicted and gas production was becoming an operational problem.

Strong gravity segregation of the injected gas was the most likely cause of the poor performance, aggravated by the unfavorable permeability distribution that caused water and gas to follow different flow paths in the reservoir and thus prevented the full recovery mechanism from being effective.

Dear Mario,

Many thanks for your post on CO2 injection. On the economics, usually the economics of CO2 injection depend on the availability of a low-cost CO2 source, plus, as you highlight, incremental oil recovery. It you have other fields in the area with either a transition zone or with relatively high residual oil levels, where miscible CO2 is possible, then you may have a perfect EOR technology at your disposal that is most likely economical.

Back to the original post on incompatible EOR vs the reservoir, as EORs are expensive and complex processes to run, a feasibility followed by lab tests, and field-pilots should precede a full field development. This pre-work is to assess whether the EOR technology works for the field or not. In full field scale, EORs are hard to keep going and the organisation needs to be ready to learn and operate these type of processes. It is very much a fail-and learn process in the beginning to get it going and to keep it going. A can-do attitude is a must to get these processes successful and some EORs fail, not only because of the EOR and the reservoir, but mainly because the organisation fails to step to the challenge.

this very general question, if you specify the conditions of your reservoir and what was the uncompatable EOR method you used we could assist you with what consquences will occur and how to eliminate the damge that may this EOR method caused.

Screening Criteria should be done to know the most suitable method you should use to recover the oil. the pilot project is essential as well when you decide one method. try to find two SPE papers talking about applying the in-situ combustion in two Romanian reservoirs, you will know the answer of your question.