Open access peer-reviewed chapter

Improving Reserves and Well Productivity Using Modern Technologies

Written By

Haq Minhas

Submitted: 20 January 2022 Reviewed: 27 January 2022 Published: 21 April 2022

DOI: 10.5772/intechopen.102897

From the Edited Volume

Crude Oil - New Technologies and Recent Approaches

Edited by Manar Elsayed Abdel-Raouf and Mohamed Hasan El-Keshawy

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The oil trapped in a reservoir rock through geological processes over millions of years is called the Original Oil in Place (OOIP). Oil recovery factor (RF) represents the recoverable fraction of OOIP. We do not have any control on the quantity of OOIP. However, the volume that we can recover is partly in our control. Through proper well placement, engineering, and production technologies, we can recover anywhere from 5 to 70% of OOIP. Exactly how much we will recover depends on the techniques employed and the nature of the reservoir. The economically recoverable oil is called the reserves. In this chapter, we will talk about various oil field technologies that can be employed to maximize petroleum reserves. We will explore some emerging technologies and processes that have helped some fields achieve 70% recovery factor while others are trailing behind, stuck at an average of 35% recovery factor, some as low as 10%. Despite all the hype, and many decades of research, Enhanced Oil Recovery (EOR) is contributing just about 4% of total world production, and most of it is from thermal EOR. We need a profound shift in the EOR technology application required to make it simple and widely applicable.


  • enhanced oil recovery (EOR)
  • improved oil recovery (IOR). Water flooding
  • upstream technology
  • recovery factor
  • field development planning

1. Introduction

Achieving highest recovery factor is perhaps an implicit success metric for any oil company. It not only improves the financial value of the company but also reflects its technical prowess. Yet the industry is hovering around a dismal average of 30% recovery factor. In this document, we will explore the blocks and block busters to reach high recovery factors in the range of 50–70%. Improving recovery factor is a two-step process, a good understanding of and the ability to control the recovery mechanisms involved. The first part needs a good reservoir characterization using the modern reservoir evaluation technologies and modeling. The second part requires deploying various technologies to economically maximize hydrocarbon recovery through a sound Field Development Plan (FDP). The FDP is perhaps the most important event in the life of an oil field. An FDP lays the foundation of whether the field will achieve a high recovery factor or remain an average recovery factor field. We cannot overemphasize the importance of FDP and therefore start this chapter with a review of FDP process and highlight some of the best practices. Reservoir management, also a component of FDP, is perhaps the second most important intangible technology having the greatest impact on recovery factor. As part of reservoir management, a periodic review of the full field after a period of production may uncover many new opportunities even in the old fields [1].

There are several enabling technologies that have large influence on recovery factors including 3D/4D-seismic, horizontal drilling, geosteering, hydraulic fracturing, intelligent completions, digital coring, machine learning, and digitalization. Enhanced Oil Recovery (EOR) is one technology that has not delivered to its promise yet. Several fields have achieved recovery factors in the range of 60–70% even without EOR [2]. There is an emerging realization to morph EOR technology to a workable tool. The long cycle of EOR projects from lab to field can be shortened and EOR should be integrated with initial field development plan rather than an afterthought as tertiary recovery. We will explore the key characteristics of various fields with high and low recovery factor to understand if it is the nature of the reservoir, fluid properties, field size, technology application, development strategy, or the team behind the field that has the biggest influence on recovery factor. Several benchmarking studies have given new insights as what really matters in recovery factors.

Shale revolution in the US is perhaps the best example of what technology can do. The combination of hydraulic fracturing and horizontal drilling with high-rate fluid injection has added billions of barrels of oil reserves from low-permeability geological formations that were considered uneconomical just 20 years ago. Today, the shale formations in the US are producing some 8 million barrel per day of oil, thanks to the technology. Still very low recovery factor of less than 10% in shale oil is a major challenge and perhaps a limiting factor to the growth and the future of shale oil and shale gas. Such low recovery factors mean more drilling to maintain production, excessive costs, and a large footprint of shale development. Achieving high recovery factors in shale oil could become a new resource of hydrocarbon, perhaps bigger than the original shale oil.

The recent EIA recommendations to ban all new exploration activities to achieve net-zero carbon emissions by 2050, the world economy recovering fast from COVID-19, rapidly rising oil price, giant discoveries becoming rare, and energy transition to renewables, is a rare combination of rising oil demand with a reduction of oil exploration. It is no brainer that adding reserves and production from existing oil fields is the only option to mitigate a looming oil crisis. It is quite doable when we look at some historical numbers summarized in Table 1.

DurationReserve addition from new discoveries (billion barrels)Reserve addition from existing fields (billion barrels)Reference
1995–2003144175Dave Cohen [3]
20041112Mike Shepherd [1]
20051210Mike Shepherd [1]

Table 1.

Historical reserve addition—new discoveries VS improvements from existing fields.

With more focus, investments, and application of new technology, we can squeeze even more from the existing fields and keep up with the desired growth in reserves. This is the main theme of this chapter. How can technologies help in extracting more petroleum reserves?

We have structured this chapter to start with the field development planning, the basic concepts of oil recovery and well productivity, enabling technologies for conventional reservoirs and shale oil, and a discussion on enhanced oil recovery. We can either push the oil toward the producing wells or we can reach the oil that otherwise cannot reach the producing well due to restricted flow paths. Or we use a combination of both techniques, pushing the oil and reaching the oil. Water flooding and most enhanced oil recovery techniques are examples of pushing the oil. On the other hand, complex wells, multilaterals, hydraulic fracturing, and various stimulation techniques are examples of reaching the oil. Reservoir permeability is a key criterion in the selection of appropriate technique.

This chapter will provide a high-level discussion of key technologies together with a focus on reservoir to increase oil recovery and well productivity. In a nutshell, with detailed knowledge of subsurface geology and fluid movements, if we can position the producing and injection wells at optimum location equipped with adequate completion jewelry, we are well on the way to high recoveries.


2. Field development plan: the blueprint of the reservoir

The fundamental job of a reservoir engineer is to engineer and maximize oil recovery and the economics of the reservoir. We use an approach as in Figure 1 for life cycle field optimization. Understanding or characterizing the reservoir is the first step in building a reservoir model. We simply cannot model something that we do not understand is a classic quote from L. P. Dake. The reservoir model is used to make an optimum field development plan (FDP). All possible development options are considered and the one with the highest financial returns and recovery is selected. Monitoring of the reservoir behavior during drilling and production is critical to ensure our reservoir models and the reservoir understanding was correct and the field is behaving as expected. In case of any surprises, we may re-engineer our FDP to still get the highest value for our investment. For example, if the oil water contact is found lower than expected, then the depth of water injection wells can be adjusted accordingly. We may need to update our models and FDP frequently based on drilling, formation evaluation, and early production data.

Figure 1.

Continuous optimization of NPV during field life.

The advancements in technology have improved this process in many ways. Many new formation evaluation techniques such as nuclear magnetic resonance, deep-investigating shear wave, deep-reading resistivity, wellbore imaging, digital rock physics, 3D seismic, and sequence stratigraphy have greatly enhanced our reservoir understanding. With the advances in well placement technologies, we can place the wells at optimum locations to maximize recovery. Modeling and reservoir simulation with high-speed computers has not only increased our response time to quickly update the models but also reduced the amount of upscaling that we had to do in the past and added more reliability in out models. The real-time data combined with data analytics is opening another avenue of opportunities and reservoir modeling. These technologies may even discover some treasures hidden in the heaps of old data.

Different stages of field development process are shown in Figure 2 and explained below

  • Appraise—After discovery-well is, we need to assess the potential of the field. Additional data are collected using seismic, drilling delineation wells, logging, coring, and well testing. At this stage, the goal is to collect all the needed data. Information is the focus at this stage. Value of Information (VOI) can be used to justify the costs. For example, whether a fault is sealing or not may necessitate or avoid drilling additional wells. Cutting down on appraisal costs and start producing the field for quick cashflow are tempting but eventually they will erode the overall value of the project. A key objective of appraisal is to reduce subsurface uncertainties—especially the one having major impact on field development such as hydrocarbon volumes, dominant drive mechanism, reservoir compartments, natural fractures, reservoir heterogeneities, and fluid characteristics.

  • Select—At this conceptual screening stage, we compare different development concepts and select the one that is most feasible for the eventual development. This feasibility study will include subsurface development options, process facilities, number and types of wells, the need and timing of pressure support, cost, and schedule estimates for every option considered. It usually starts with ruling out the options that are technically not feasible.

  • Define—The most feasible selected concept from previous stage is used for a detailed field development plan (FDP). It encompasses the complete chain from subsurface to surface and delivery. Simulation models are used to study multiple what-if development scenarios together with subsurface uncertainties and make multiple production forecasts. These multiple production forecasts range from P90 being more conservative scenario to more optimistic P10 case. The most likely P50 is often used as the basis of development. Complete costs of the project including drilling, completion, facilities, operating costs, operating philosophy, and revenues are used to sanction the project. The FDP is an important document. It is a kind of promise by the development team using their best knowledge and skills that the project will produce X barrels at a cost of Y$. Thus, a key financial metric is minimizing Cost/Barrel. Typical FDP documents consist of the following components:

    • Objective of the development

    • Details of geoscience and petroleum engineering data used for the modeling

    • Production forecasts of the models including low, median, and high case

    • Description of engineering facilities

    • Cost estimates

    • Operating, maintenance, and reservoir monitoring protocols

    • Project planning

    • Project economics

    • Budget proposal

  • Execute starts after approval of FDP. It consists of detailed design of facilities, procurement of materials, fabrication of facilities, installation of facilities, and commissioning of the facilities and equipment as shown below in Figure 3. The process may vary a lot from onshore to offshore development. In onshore development, production may start as the first well has been drilled. In offshore, production may have to wait for the facilities to complete and commission.

  • Operate phase. Minimizing the time between discovery to the first oil is often an important goal of the overall field development. Once the field starts producing, the production and the pressure data are compared with the prediction of the initial model in a process called history matching. This is to validate whether the reservoir is performing as projected by the models and may provide substantial opportunities for further reservoir understanding and optimization. For example, if we had assumed a fault as sealing in the model which was not sealing in real, then some of the production data may not match the model until we allow communication across the fault. The modern reservoir management uses a life cycle approach as shown in Figure 1. Continuous monitoring and periodic adjustment of the reservoir models ensures optimum reservoir performance and update to the field development plans if needed. Quite often, we update the models and adjust the field development plan many times during the life of a field as shown in Figure 2 labeled FDP-1, FDP-2, FDP-x. While FDP-1 is green field development, FDP-2 and the later FDPs are part of the brown field development.

  • Changing focus during different phases. During different stages of development, the importance or focus changes from maximizing information at appraisal stage to optimization during early development to cost saving during development. The curious and questioning mind set of “do what is right” changes to an executor mind set of “do the things right.” Some companies use the analogy of thinking hats. The project team uses three different hats: a) information gathering hat, b) do the right development hat, and c) do the development right hat. However, there is often some overlap. We may get new information even during development and production stage that is crucial to reservoir understanding. Likewise at the appraisal phase, we have some idea of the ultimate development and collect the relevant information.

Figure 2.

Stage of field development for conventional reservoirs. Our focus changes over time from information collection to optimized development to minimizing costs.

Figure 3.

Execution of field development plan.

Smart fields are a further enhancement to above approach shown in Figure 1. In this case, flow rate from each well and if possible, from each segment of horizontal wells or each zone can be adjusted to ensure uniform production from the entire reservoir and achieve a uniform injection. This results in large gains in recovery.

2.1 Assurance review of FDP: a cold-eye review

Assurance review process or value assurance review, a routine practice in most companies is a proven process that can add substantial value to any project. Essentially, a team of experts will review the project in detail to identify any gaps or improvements before the project goes to the management for funding. However, in some cases the process may become a formality with little value addition. There are two versions of assurance review—a power point review and a consultation review. In a power point review, the project team presents the final project to the review team in a presentation session. Such review may uncover some key shortcoming in the project but not everything. In a consultation review, the review team will spend few days with the project team to go through every detail and suggest any improvement or alternatives if needed. Such a session can significantly improve the skills of the project team as a by-product of project review.

The review team could be internal or external. Internal teams may have the advantage of having the background knowledge of local geology but may have biases toward the project or conflict of interest if there are mutual reviews. Review by external teams, the so-called cold-eye review, could be more effective especially by industry experts who have reviewed hundreds of other projects and carry with them decades of knowledge.

2.2 Giving the old fields a new life

There are many examples where a field may not have started with an optimum development plan. This happens mostly with old fields. A full-field review of such underperforming fields can often uncover many new opportunities to improve production and recovery. Usually, the past costs are considered sunk costs and forward economics is used for any investment decisions in these projects. Figure 4 shows an example of a field revival from Venezuela. In 1995, the production had declined to one fourth of initial levels and it appeared as if there is little left in the field. But a new reservoir understanding following an integrated study and application of new technologies revived the field again. The literature is rife with such examples where many oil fields got a new life after a study and a dose of new technology.

Figure 4.

Better reservoir understanding followed with additional wells and recompletion of existing wells resulted in large production increase—example from Venezuela (Hamilton 2002).

There are several reasons to revisit old fields to extract the remaining oil:

  1. Integrating years of well and production data from a producing field often gives a new understanding about the reservoirs and identify new opportunities.

  2. Several new technologies have been developed over the years that can give a boost to the old fields that initially did not get benefit from such technology.

  3. Benchmarking studies of similar fields can quickly identify underperforming fields and highlight the production and recovery gaps. There was an excellent application of benchmarking by Oil and Gas Authority (OGA) for UKCS. Fields having similar geology or reservoir quality should have comparable recovery factors. One of the relations for reservoir quality index (RQI) can be defined as RQI = permeability*thickness*Porosity*(net/gross) *(pressure/TVD) A plot of RQI vs. recovery factor for different reservoirs is a quick method to screen underperforming fields. Recovery factor is the projected value for the field life based on DCA or FDP. Such benchmarking can also be used for new developments as a quick quality assurance of the development plan.

2.3 The role of new technology in field development

Several new technologies have been developed that have significantly transformed field development planning. This includes new measurements for formation evaluation, advances in computing power and modeling, advances in drilling technology, well placement, completion, and instrumentation.

2.3.1 New measurements for formation evaluation: Deeper and clearer

There are several technologies that have radically improved formation evaluation and help in better reservoir characterization.

  1. Nuclear magnetic resonance provides a better rock characterization at pore scale through pore size distribution, permeability, and differentiate between bound and free fluid—that was not possible with traditional logs in the past. It can also identify the type and properties of hydrocarbon in the pore spaces. In particular, the permeability and bound fluid information is most valuable in fluid recovery. NMR is a technology borrowed from medical science which is finding many new applications in formation evaluation.

  2. Deep-reading resistivity and electromagnetic measurements can identify the fluid type 100’s of feet away from the wellbore. With traditional measurements, we could get a detailed high-resolution picture of the rocks next to the wellbore, but what is in-between the wells was mostly unknown. The best we could do was to build a layer cake model based on well-to-well correlation. With deep reading measurements, we can not only identify heterogeneities 100’s of feet away but can also locate any by passed oil or position the wells in optimum location with the knowledge of reservoir boundaries and layers.

  3. Digital rocks combine the micron-level images using micro-CT-scan and SEM with wettability and contact angle measurements to model 3D multiphase fluid flow in porous media. Such pore scale modeling has wide applications in recovery process. It can be used to obtain relative permeability data for every rock type and with a turnaround time of weeks what used to take several months from the lab measurements. This can significantly improve the quality of reservoir models and speed up the development.

  4. Several wireline measurements can now be made with while-drilling technology. This real-time formation evaluation is the backbone of geosteering that allows the well to track the reservoir at optimum location through well placement technology.


3. The elements of well productivity

The fluid flow from reservoir to wellbore through porous media is described in Eq. (1) below. This is a solution of diffusivity equation for an ideal homogeneous reservoir.


In this equation, q is flow rate, k is reservoir horizontal permeability, pr is the reservoir pressure, pwf is the flowing bottom hole pressure, Bo is oil formation factor which is the ratio of reservoir volume to surface volume of oil, μo is oil viscosity, re is the reservoir radius, rw is the wellbore radius, S is the wellbore skin that indicates the connectivity of wellbore to the reservoir, a positive value shows a poor connectivity or flow restriction in the near wellbore region such as damage wellbore, a negative value on the other hand suggests improved flow paths in the near wellbore region typically created by stimulation or hydraulic fracturing.

We will use aforesaid equation to explore how we can use various well technologies to maximize flow rate. In a later section, we will consider how to maximize total recovery from the reservoir. The flow rate q (bbl/d) in Eq. (1) is controlled by the following parameters.

  1. Reservoir Pressure, Pr, the higher it is the higher the flow rate will be. At the time of the reservoir discovery, we find the initial reservoir pressure (pi), later it will reduce or deplete with production. The production will start declining as the reservoir pressure Pr reduces as in Eq. (1). We often try to maintain the well production by gradual reduction of surface pressure, by increasing the choke size, and produce the well at constant rate before the inevitable decline in well production when the surface pressure has reached its minimum. To avoid this production decline, we often try to maintain reservoir pressure through pressure maintenance by injecting water or gas. The ratio of injected volume to produced volume is called voidage replacement ratio (VRR), which is monitored in any water flood project to ensure adequate injection. Water or gas injection has another more important function as well. It displaces oil in addition to providing pressure support. Water injection through vertical wells is not very efficient as it creates localized regions of high-pressure and high-water saturation resulting in water breakthrough and poor reservoir sweep. New technologies such as horizontal wells equipped with inflow control devices, or diversion technologies, allow a more uniform water injection and production through long-distributed length of horizontal wellbore rather than a single-point injection and production from vertical wells. We can manipulate reservoir pressure and fluid displacement through several waterflood technologies.

  2. The production will increase as we reduce the wellbore pressure, Pwf, thus increasing the drawdown pressure between the reservoir and the wellbore. Since the wellbore pressure also provides a lifting force to the fluid to reach the surface, reduction in wellbore pressure will reduce the lifting pressure for the fluid in the wellbore. There is a limit as to how low the wellbore pressure can be reduced before the well stops flowing. During the field life, we continue reducing Pwf by adjusting the surface choke as the reservoir pressure Pr reduces to maintain flow rate. As a last resort, we provide artificial lift systems to add external energy to the fluids to reach the wellhead. The artificial lift systems include different types of pumps such as Electrical Submersible Pump ESPs or Jet pumps that add energy to the fluid or gas-lift method that makes the fluid lighter by mixing gas in the fluid stream. Artificial lift systems are an important instrument to increase well production by lowering the bottomhole pressure Pwf and still enabling the well to keep flowing at surface.

  3. The remaining factors in Eq. (1), Reservoir permeability k, reservoir thickness h (ft), fluid viscosity, μ (cp), are equally important. Though we have no control on permeability, thickness, and fluid viscosity, we can ameliorate the situation somewhat when these parameters are not optimal as explained in the sections a, b, and c below.

    1. Flow rate will be high in a high permeability and large reservoir thickness. In case of low-permeability reservoirs, we can use hydraulic fracturing to get reasonable flow rates and make the marginal wells more profitable. In the extreme case of nano-Darcy reservoirs such as shale reservoirs, the well may not flow at all without hydraulic fracturing. As shown in Figure 5, fractures in low-permeability reservoirs can increase the overall system permeability many times compared with the unfractured matrix permeability (100 or 1000 times or even more depending on the matrix permeability). Hydraulic fracturing creates system permeability in two ways. It creates new hydraulic fractures, parallel to maximum horizontal stress that can be preserved through proppant or sand placement in the fractures. Conventional wisdom is that these hydraulically created fractures parallel to maximum stress are easier to open and easier to remain open and these are the ones responsible for increase in production in low-permeability reservoirs. However, hydraulic fracturing also activates and makes conductive the existing natural fractures in shale or tight formations, especially the critically stressed fractures that are aligned at small angles from maximum stress orientation, typically +/− 30o to maximum horizontal stress. This happens by small shear movement in the fractures as shown in Figure 6 [5]. This also explains why slick water, with no proppant, has been working so well in many shale formations. It also explains a frequently observed mismatch between production logs and the occurrence of natural fractures. Mostly, the fractures aligned with critical stress orientation are seen to dominate the production. This concept is motivating shale drillers to orient wells to target the critically stressed natural fractures. Fracturing then is the obvious choice in low-permeability reservoirs as it will increase the overall or the system permeability.

    2. In highly viscous oil, we can use heat or steam to reduce the oil viscosity and improve well production. Such thermal recovery techniques are often used for heavy oil. These techniques are both a production enhancement and recovery improvement techniques. Heavy oil may not produce at all or may not produce at economic rates if not heated.

    3. Reservoir thickness is as important as permeability in terms of impact on flow rate. Thickness is more predictable as it has often less variability than permeability. Unlike permeability, there is little that we can do about it. Generally, vertical permeability is much lower than the horizontal permeability—particularly in clastic reservoirs. This makes horizontal wells less effective in very thick zones as the reservoir regions hundreds of feet above or below the horizontal well may not be able to produce due to low vertical permeability. In thin reservoirs, the horizontal wells might compensate the reduced reservoir thickness by increasing the reservoir contact area. Every situation must be modeled to compare different well types since the exact reservoir properties and their vertical distribution can be more important than the mere mention of thin vs. thick reservoir.

Figure 5.

Fold of increase in the overall system permeability due to the presence of fractures. These fractures could be natural fractures or man made through the process of hydraulic fracturing (ref. [4]).

Figure 6.

Shear movement in existing natural fractures creates conductivity in natural fractures, which can be otherwise closed. After movement, the fracture face leaves a small opening that provides a conductive path for fluid to flow.

Although in the aforesaid discussion improvement in well productivity was the focus, in most cases both the well productivity and the fluid recovery are linked together. Water flooding improves well productivity by maintaining reservoir pressure, and improves recovery by prolonging well life and mostly by fluid displacement. Hydraulic fracturing is historically used to increase well productivity by reducing the wellbore skin. This also reduces the abandonment pressure and thus improves the fluid recovery. In very tight formations to shale reservoirs, the wells may not produce economically without hydraulic fracturing. In this case, hydraulic fracturing will increase both the well productivity and the reserves.


4. Low oil recovery factor: still a challenge for petroleum industry

A global average 30% Recovery Factor in oil reservoirs is a major challenge for petroleum industry as identified by SPE in its six grand challenges [6]. Such low recovery factors also make us one of the least efficient industries in terms of input to output ratio. Can we do any better? Yes, it is indeed doable as proven by many oil companies that have raised the bar of recovery factor to 50% or more with water flooding in combination with new technologies. Even a 70% recovery factor is not out of reach. Saudi Aramco’s has launched a plan to raise its recovery factor of major producing fields from current 50–70% [7]. A study of 730 sandstone reservoirs was carried out [8] to understand what drove some reservoirs to achieve very high recovery factors. Key traits of high recovery reservoirs include homogeneous and good-quality reservoirs with strong water drive. Important observations of this study are highlighted below:

  • P50 Primary recovery was 15.5% While P50 ultimate recovery is 38.5%. This shows the importance of secondary recovery. A 13% primary recovery reservoir was able to achieve an ultimate recovery factor of more than 60% through pressure maintenance.

  • While mean ultimate recovery of 636 fields was 38.5%, 10% of the fields achieved 58% or higher recovery.

  • EOR is not a key factor in achieving high recovery factors.

In short, we can achieve high recovery factor by following the best practices of reservoir management.

4.1 Fundamentals of oil recovery

Natural depletion of reservoir pressure, called the primary recovery, uses only the natural reservoir pressure support. This support could come from expansion of oil above bubble point pressure, release of solution gas below bubble point pressure, influx of gas from gas cap, or influx of water from possible connected aquifer. Often such natural pressure supports are either weak or absent and may result in very low recovery factor, except in very strong water aquifer. Recovery factor from primary recovery is less than 20% in most cases. In some countries, the regulators do not allow producing some oil field purely in primary recovery phase to achieve maximum recovery.

4.2 Secondary recovery

The secondary recovery using water or gas injection is used in majority of the fields. Globally, the combined recovery factors from primary and secondary recovery range between 35 and 45% [9] or an additional 15–25% recovery attributed to water injection. The purpose of water injection is to provide pressure support and displace oil with water. The injection will be more effective when the injected water can push the oil like a piston. However, it rarely happens. The injection water often fingers through oil due to its lower viscosity, wettability effects, and reservoir heterogeneities. Significant quantity of oil is left behind after water flooding. Even without any Enhanced Oil Recovery techniques, water flood projects can achieve an additional 10–30% recovery factor as proven by several high recovery water floods. This was achieved by a combination of new technology and reservoir management. Recovery factor from water flooding or gas flooding is approximately given by the following relation,


  • Eps is pore scale or microscopic flooding efficiency. The mechanism of un-swept oil at pore scale is explained in Figure 7. Enhanced Oil Recovery (EOR) techniques such as miscible flooding are used to increase Eps.

  • Es is the macroscopic flooding efficiency. The injected water could completely bypass part of the reservoir and leave it un-swept as in Figure 8. EOR techniques such as polymer or diversion techniques can be used to increase Es. The ideal water flood should have a uniform flood front, termed as water conformance. Various near wellbore and deep-reservoir diversion techniques are used to improve water conformance and the resulting Es. Figure 9 illustrates how the addition of polymer to water can improve its sweep efficiency by making the water more viscous and sweep the oil in a more piston like manner.

  • Ed is the fraction of the reservoir volume connected to any well. Ed is adversely affected in reservoir with vertical or horizontal barriers, or compartmentalized reservoirs. Reservoir understanding combined with horizontal or multi-lateral wells or infill wells has helped the industry greatly increasing Ed.

The different components of recovery mechanism as depicted in Eq. (2) suggest that we must understand and then control recovery process from pore to reservoir scales (Figure 10).

Figure 7.

Microscopically bypassed oil during water flood in a water wet reservoir (Eps). The oil is in red, grains in yellow and water in blue color. The figure on the left shows the original oil and water saturations before water flooding. The figure on the right shows the saturations during water flooding (ref. [2]). In water wet reservoirs, the water moves around the grains and small pore throats leaving some oil trapped in the larger pores.

Figure 8.

Macroscopically bypassed oil (Es). Water flood from left flows through higher permeability, by passing oil in the lower right in a 6-m-thick layer (ref. [2]).

Figure 9.

Improved sweep efficiency of water after adding polymer due to lowering of water mobility (ref. [10]).

Figure 10.

Example of oil left in isolated compartments (Ed).

As shown in Figure 1, the reservoir understanding starts even before drilling the first well, and the field appraisal is done to improve reservoir understanding and reduce the reservoir uncertainties. A field development plan is then formulated based on the best reservoir understanding at that time. The field production and monitoring provide the dynamic reservoir information when the fluid movement takes place in the reservoir. Despite all these data collection activities, our reservoir understanding is often far from perfect, especially in complex geologies. Often the reservoir data are fragmented among different disciplines. Integration of every piece of data is the first step behind reservoir understanding. Complex geological models are a great tool to pull all these data together. Reservoir simulation is then used to evaluate different development and production options and select the most optimum one to build a field development plan. History matching the model with production data provides another dimension of reservoir characterization, which is based on reservoir performance. It helps in understanding the reservoir compartments, communication with aquifer or gas cap, and reservoir heterogeneities. These models can then help in predicting the performance of different water flood techniques to select the most optimum option.

4.3 Formation evaluation

Our journey to reservoir understanding starts with an initial geological model, which is built using surface acquired seismic, gravity, or magnetic surveys. Well drilling provides the first source of direct measurements in the subsurface. Well logs in the form of gamma ray, density, resistivity, neutron, sonic, caliper, nuclear magnetic resonance combined with rock, and fluid sampling have been used for many decades. A whole science of understanding rock and fluid distribution in the near-wellbore formations is based on these well logs, which is collectively called formation evaluation. Reservoir dynamics involve the measurement of reservoir pressure during fluid movements in the rocks few centimeters or few hundred of meters away from the wellbore using formation testers or transient well testing. The objectives of formation evaluation can be classified as below:

  • Lithology and well-to-well correlation using spontaneous potential, gamma ray, and photoelectric effect.

  • Capacity of the rock to store fluid, The Porosity using density, neutron, sonic, photo-electric effect, nuclear magnetic resonance (NMR), resistivity, and induction

  • Ability of the rocks to allow fluid movement, The Permeability from NMR, formation testing, or sonic

  • Fluid characteristics from resistivity, Induction, or fluid samples

  • Geological information such as faults, fractures, depositional environment using borehole images, caliper, dipmeter

In the past, aforesaid measurements were made with wireline tools after drilling the well. The downhole data are transmitted to surface using electrical cables called wireline. With advances in technology, most of these measurements are now possible while drilling a well and the data transmitted to surface in real time using mud pulses or measurement while drilling technology. The logging while drilling or LWD provides data for formation evaluation as soon as or soon after the drilling bit penetrates the rocks. LWD has become essential for placing the well or steering the bit at optimum location in the reservoir in geosteering systems.


5. Oil recovery from tight matrix in fractured reservoir

Naturally fractured reservoir with tight matrix is perhaps the most difficult reservoir to achieve a decent recovery factor. Any water injection scheme will quickly flood the fractures, leaving most of the oil untouched in the matrix. In primary recovery phase, in the absence of any pressure support, the oil filled in the open fractures will be produced as flush production. The pressure inside the fractures will reduce over a short period of time as recharge from tight matrix to the fractures is very slow. In case of depletion drive, the tight matrix will continue recharging the fractures, though very slowly, resulting in a long tail of low production after the initial flash production. In case of strong connected aquifer, the fracture could quickly result in high water cut. The result is traditionally very low recovery factor in such reservoirs in both primary and secondary recovery phases. The shale reservoirs are even worse in terms of recovery factors and much more challenging since the matrix permeability is extremely low. Injecting any fluid into matrix in the presence of high-permeability fractures is a challenge. Several CO2 EOR huff-n-puff trials have shown some promising results in shale oil. These EOR technologies combined with controlled hydraulic fracturing and flow diversion technologies may give a new life to conventional fractured reservoirs with tight matrix as well. In many shale formations, the natural fractures are often closed and non-productive. In several studies, modeling, and micro-seismic during hydraulic fracturing have shown that fracturing with high-rate slick water can potentially make these close fractures conductive through shear movement, especially those aligned with present day stress. This is earlier shown in Figure 6.

5.1 The complex wells: Taking the well to the reservoir

The drilling technology together with measurement while drilling has become so advanced that we can drill wells almost along any trajectory that is optimum for reservoir management. Maximizing well to reservoir contact has greatly improved both the production per well and the recovery factor as well. Vertical wells are drilled with rotary drilling rig where the bit turns using a turntable at surface connected to the bit through hollow drill pipes. Horizontal drilling was traditionally done with mud turbine where the bit turns by the flow of mud. In this case, the pipe does not rotate. The pipe just slides as the bit is cutting through the rock. The more advanced Rotary Steerable System (RSS) uses a combination of downhole motor and pipe rotation. This system in combination with geosteering system can make the well track very complex geologies.


6. The smart wells: Taking the chokes downhole

Non-uniform production and injection from horizontal wells had been a major challenge for production engineer. An early excitement about long horizontal wells died after realization that productivity from horizontal wells was much less than expected considering the length of the well. Many production logs and well modeling revealed that higher pressure drops at the heel of the well resulted in higher production at the heel compared with the toe of the well. The result was less production from the toe of the well and often water or gas breakthrough near the well heel. Reservoir heterogeneities along the wellbore multiplied the problem of non-uniform production from horizontal wells.

An obvious solution was to introduce multiple downhole chokes called inflow control devices (ICD). Model-based flow restriction, ICD’s is placed along the well length together with isolation packers that would result in more or less uniform production or injection along the well length. A more advanced version of flow control allows the adjustment of choking from surface. Such flow controls devices are called Inflow Control Valves. Downhole measurements of rate, pressure, and temperature can also be added. With surface control system and data transmission to a central location—this now becomes a smart well—part of a smart or intelligent field. Production or reservoir engineers from their offices can not only monitor but also control well production or even production from any section of the well. This has provided a huge boost to both production and recovery factors.


7. Technologies for tight and shale reservoirs

Hydraulic fracturing has been around for nearly 70 years. There had been a million fracturing jobs from 1940 to 2000. Another 6 million treatments were added from 2000 till now. More than half of the US production is attributed to hydraulic fracturing. Perhaps, hydraulic fracturing is the second most important technology after drilling. In addition, hydraulic fracturing is a very forgiving technique. We can often get away with good production increase even from an imperfect job. The success of this technology was its own enemy. For long time, there were no new developments in hydraulic fracturing. In many companies, it was called pressure pumping. Most fracture models were assumed as planner fractures in solid material, ignoring the presence of porosity, natural fractures, and other heterogeneities. The success of shale gas from early 2000 and later shale oil from 2007 motivated the service industry to come up with several new frac fluids, proppants, and the equipment. Efficiency of frac operations, cost reductions using pad drilling, horizontal well placement, slick water, and zipper fracs were the other major improvements. Real-time fracture monitoring using micro-seismic, downhole pressure monitoring, analysis of treating pressure, and experience of millions of treatments has tremendously increased our understanding of hydraulic fracturing in tight formations. Realization that natural fractures may re-activate during pumping as shown in Figure 6 clearly negated he earlier assumptions of planner hydraulic fractures. All these developments in multiple technologies resulted in nearly 8 million bbl/d of shale oil. Figure 11 below shows how the production from multi-stage fracturing in horizontal wells has impacted the overall US oil production.

Figure 11.

US oil production historical chart. Without shale oil, the US oil production would have been around 4000 bopd. Shale oil production reached to nearly 9000 bopd. It stands again nearly 8000 bopd, after the slowdown from COVID-19.


8. Enhanced oil recovery (EOR): the pinnacle of reservoir engineering

Enhanced oil recovery (EOR) is oil recovery by the injection of materials not normally present in petroleum reservoirs. Despite lot of research EOR has not delivered in traditional applications in the form of tertiary recovery after water-flooding. Recently, many new concepts have emerged where EOR is being considered from early on rather than a late stage or tertiary form of recovery. Several successful polymer flooding together with the initial water flooding has been very successful. Low salinity water flooding is another promising technique that can significantly improve recovery without any new facilities. Despite a long history of EOR, a strong need of improving recovery factor, and lot of research on EOR, the total EOR contribution is just about 4 million bbl/d for the whole world. What is the reason of such dismal performance of EOR technology, and can we change EOR strategy to make it a success?

  1. EOR projects are a huge commitment for any company as it needs large investments. It often involves board-level decision making or decisions by higher management before any work can start. Most project get shot down at this stage.

  2. EOR takes a long time from lab testing to modeling and pilot testing. By the end of this long process, oil price or other economic factors would change so much that EOR projects would be shelved before implementation.

  3. The performance of most EOR projects has been poor. Recovery from EOR technique has been far less compared with the expectations.

  4. EOR has earned itself a bad reputation of being expensive and risky.

  5. A combination of horizontal, multilateral wells equipped with smart downhole flow control valves and good reservoir management has enabled simple water flooding to achieve rather high recovery factors, sometime reaching or exceeding 60%. With this, the appetite for EOR has reduced. This is already a big achievement for the industry that was stuck with 30% recovery factor in the past.

The aforesaid does not mean a gloomy future for EOR. Going back to Eq. (2), the multilateral smart wells may increase macroscopic sweep efficiently Es and connected volume efficiency Ed, but the microscopic efficiency factor Eps can only be altered by some EOR technique. EOR may also increase Es beyond what smart well technology can do. The smart well technology could become an enabler of EOR. With advancements in computing power, the simulation models can incorporate the full physics and chemistry of EOR process now. Once calibrated with lab experiments, we may not need pilot testing for every EOR project. The fear of EOR should gradually go away once EOR becomes easy and more docile rather than frightening for the management. There are some field developments where EOR was considered from day one of field development such as polymer flooding or flooding with smart water. Perhaps, the term EOR should disappear completely and get integrated with secondary recovery. EOR, as is defined today, is not the only and the best route to high ultimate recovery.

8.1 Recovery factor in shale oil: still a challenge

While producing oil from dense shale rocks that had been discarded for many decades was a great achievement that has revolutionized the oil outlook in US and the rest of the world, an average recovery factor of less than 10% is a major challenge. Improving this recovery factor could unleash a huge new resource of oil. In Bakken alone, the in-place volume of shale oil is around 900 billion barrel. Projected recovery factor for Bakken is only 7%. Increasing this number by 5 or 10% can give hundreds of billions of barrels of additional oil. There is a huge prize if any of the ongoing EOR trials become successful. The reason of low recovery factor in shale rocks is very low matrix permeability in the range of micro- to nano-Darcy resembling concrete or even granite. It takes a long time for fluid to move from tight matrix to the fractures. With multistage horizontal wells, we create a stimulated volume of rock around the wellbore, which is a network of fractures or re-activated natural fractures. After fracturing, the oil from the fractures flows into the wellbore but the production quickly declines as the total volume capacity of the fractures is very small. The oil now moves very slowly from matrix to the fractures, and the well continues flowing at a very low rate for many years. Depletion drive with no pressure support is the other reason of low recovery factor. Even in a conventional reservoir depletion drive recovery factor would be around 15% in a low-permeability reservoir.

Several EOR techniques are being investigated that include miscible gases, surfactant, and low-salinity water flooding.


9. A journey toward 70% recovery factor

Achieving 70% recovery factor is not a destination but a journey. The closer we get to high recovery factor, the more difficult and expensive it will become to improve it further. Identification of potential oil traps from early reservoir studies is extremely important. For example, in a good permeability homogeneous formation, viscous fingering and fluid by-passed at pore level needs attention by controlling mobility ratio of injection fluid. In multi-layered system, the oil in low-permeability layers is likely to remain undrained without diversion technologies. In random reservoir heterogeneities such as in some carbonate reservoirs, deep-reservoir diversion technologies could be more effective. In tight matrix-fractured reservoir, fluid will drain quickly from fractures, and any water injection will quickly flood the fractures leading to extremely high water cut, while bulk of the oil in matrix will remain unproduced. Unlocking matrix oil is the key in this case. In short, there is no magic bullet to reach the high recovery factor. It is a journey where we should target the big and the easy oil first—which is often the low hanging fruit. As in Figure 11, maximizing ED should be the top priority. If the oil is stranded in some compartments and we use expensive EOR chemicals to improve pore scale recovery factor, it will be a blunder. Next improving sweep control is the most important. If water is unable to reach any part of the reservoir, it is unlikely for expensive chemicals to reach there either. Addressing pore-level displacement is most difficult and often the last shot. As a quick check, in a situation of very low recovery factor in the range of 20–30%, it is probably reservoir connectivity (ED) or reservoir sweep (ES) that needs attention (Figure 12).

Figure 12.

Path to getting highest recovery factor. Get the low-hanging fruits first. Maximum value comes from initial development plan.


10. Conclusion

Figure 13 summarizes the key parameters or activities that have greatest influence on recovery factor of conventional reservoirs. For heavy oil, the efficiency of Cyclic Steam Stimulation (CSS) or steam flooding and well spacing will be more important.

Figure 13.

Key influencers in recovery factor.

A strategy to high Recovery Factor is described in this paper based on the authors personal experience and recent benchmarking studies,

  1. A good reservoir understanding is the starting point. New higher resolution and deeper measurements together with 4D seismic can radically improve reservoir characterization from micrometer to hundreds of meters.

  2. Computer models can capture complex geological details thanks to the advances in computing. Oil displacement from micrometer to tens of meters can be modeled for optimum recovery of hydrocarbon. Fluid displacement experiments using digital cores or labs are incorporated in the models. Giga cell reservoir models using fast computing have minimized the need of extensive upscaling that had oversimplified and homogenized a complex subsurface in the past.

  3. The Field Development Plan (FDP) is made using aforesaid models that dictate the number, type, and placement of the wells for optimum sweep and uniform drainage. Various diversion technologies from mechanical, to fluid based and nanotechnology, are used to maximize sweep from every part of the reservoir. Simple EOR techniques such as low salinity water or polymer flooding can be integrated with initial development plan.

  4. Advances in technology can help in drilling and completing such complex wells to achieve maximum reservoir contact.

  5. Continuous reservoir surveillance is then used to timely react to any deviation of the reservoir behavior from the one anticipated from FDP and react to it timely. Deep-reservoir monitoring using nanorobots is expected to take reservoir surveillance to the next level.

  6. A survey of high recovery fields shows that the technologies of water flooding, well construction, reservoir modeling, and smart fields are some of the key differentiators between low recovery fields vs. high recovery fields other than the size and the nature of the reservoir.

  7. With aforesaid workflow, we can be well on our way to high recovery with optimum reservoir sweep. The pore-level displacement can then be improved using surfactant or miscible gas flooding using Enhanced Oil Recovery techniques if economical.


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Written By

Haq Minhas

Submitted: 20 January 2022 Reviewed: 27 January 2022 Published: 21 April 2022