Results

A pilot water flood was carried out in the Marrat reservoir in the Magwa Field. The main aim of this pilot was to allow an assessment of the ability to sustain injection, better understand reservoir characteristics. A sector model was built to help with this task.
An evaluation of the injectivity in Magwa Marrat reservoir was performed with particular attention to studying how injectivity varied as injected water quality was changed. This was done using modified Hall Plots, injection logs, flow logs and time lapse temperature logs.
Data acquisition during the course of the pilot was used to better understand reservoir heterogeneity. This included the acquisition of pressure transient and interference data, multiple production and injection logs, temperature logging, monitoring production water chemistry, the use of tracers and a re-evaluation of the log and core data to better understand to role of fractures.
A geological model using detailed reservoir characterization and a 3D discrete fracture network model was constructed. Fracture corridors were derived from fractured lineaments interpreted from different seismic attribute maps:
A sector model of the pilot flood area was then derived and used to integrate the results of the surveillance data. The main output is to develop an understanding of the natural fracture system occurring in the different units of the Marrat reservoir and to characterize their organization and distribution. The lessons learned from this sector modeling work will then be integrated in the Marrat full field study.
The work described here shows how pilot water flood results can be used to reduce risk related to both injectivity and to reservoir heterogeneity in the secondary development of a major reservoir.

Over a thousand well pairs in five different fields in Western Canada have been examined using communication analysis techniques. The results of this analysis strongly suggest that in addition to conventional Darcy type flow through the matrix rock, there is also strong communication between wells through induced fractures, and/or natural fractures.

Most of these five fields are not typically thought of as naturally fractured. Nonetheless this type of fracture flow exists. It is highly likely that these hot streaks are pressure sensitive and therefore have a geo-mechanical component that controls permeability. The geo-mechanical component means that permeability can vary with time and injection pressure. This work on the Western Canadian Sedimentary Basin (WCSB) is similar to work done by Heffer in the North Sea.

Conclusions

Reservoir heterogeneity is the primary cause of poor sweep efficiency and complex flow paths. In order to study reservoir heterogeneity at a field level, we used a communication analysis tool. A key question though is; what type of heterogeneity controls flow? Is it matrix flow, induced hydraulic fracture flow or both?

In an effort to systematically characterize flow in a uniform manner, a communication analysis tool was applied on five waterflood fields and 1400 injector producer pairs. Combining the work done in this paper with our experience in WCSB and worldwide injection projects we see that although each field is somewhat unique there are common phenomena in many injection projects.

Produced water reinjection is gradually becoming a preferable option for water disposal because of increasing stringent environmental regulations. During long-term injection, a fracture usually initiates from the injection well and then grows deep into the formation. The growth of this fracture and the long-term injectivity are mainly influenced by formation properties, solids loading in water, in-situ stresses and well trajectory. Fracture growth and injectivity during produced water reinjection are influenced by long-term leak-off processes, thermo-poroelastic changes within the formation and the intermittent injection nature.

This paper presents an approach for systematic considerations of critical issues that greatly influence the well trajectory, completion, fracture growth and long-term injectivity. The approach was applied recently to two field cases for planning and decision-making: one field in Australia and the other field in the UK North Sea. The effects of the following issues on fracture growth and injectivity were addressed in the North Sea field case: in-situ stress magnitudes and direction; thermo-poro-elasticity; solids loading; perforations, tubing strength and pump capacity; and operational issues to maintain injectivity. Although the above issues were common to the Australia case, the special challenge came from high solids loading in water requiring a very large fracture to store solids particles.

Highlights of the study results include (1) potential fracture growth complexity and injectivity loss, (2) high pressure loss requiring high pump capacity, (3) undesirable fracture growth risking well completion and surrounding structures, and (4) fracture tip plugging by formation debris during intermittent injection. Mitigation strategies for all these complexities are also addressed in the paper.

The paper will guide engineers when addressing geomechanical, fracture growth and injectivity issues at the planning and designing stages of a produced water reinjection well.

Waterflooding has been an effective improved oil recovery process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures could be reactivated and/or new fractures could be created. Similar effects could enhance hydrocarbon recovery in shale reservoirs.

In this paper, we calculated the magnitude of water injection-induced stress using a coupled flow-geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical simulation study for a sector model was carried out. Stress changes due to the volume created by the hydraulic fracture, water injection, and oil production were calculated. Hoek-Brown failure criterion was used to compute rock failure potential.

Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promotes rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO₂ EOR techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture where much of the undrained oil resides.

Conventional recovery methods (e.g. waterflood) usually recover 50% of the oil in place. This number is even lower in fractured resources where water selectively channels through the fractures towards producers leaving much oil trapped in the matrix. The objective of this work is to investigate the improvement of oil recovery in fractured carbonates at low interfacial tensions (IFT) between oil and aqueous phases while accounting for gravitational effects. Experiments are conducted on cylindrical cores that are surrounded by fractures. The experiments are monitored by an X-ray CT scanner. Images are collected multiple times at each flooding stage to track front movement and quantify local fluid saturation. To achiever our objective, two experiments are needed in two orientations: horizontal (base case) and vertical. This work describes the experimental setup and the base case. In the base case, waterflood then surfactant flood were implemented in a spontaneous imbibition scheme. The waterflood recovered 37% of the original oil in place while the surfactant flood did not recover any oil.

In laboratory experiments a surfactant was injected into the fracture of an oil-wet fractured limestone to alter the wettability of the fracture surface to increase waterflood oil recovery. After a short shut-in period, the system was waterflooded to study the fluid transport from the fracture to the matrix and the oil recovery. The results were compared with waterfloods without surfactant treatment to isolate the effect of wettability changes on the fracture surface during water based EOR in oil-wet, fractured carbonate reservoirs. Differential pressure across each matrix block was measured, and magnetic resonance imaging (MRI) was used to obtain dynamic in-situ fluid saturation distributions, both in the matrices and within the fracture itself. A capillary threshold pressure for water to invade the matrix blocks was observed. Waterfloods after surfactant treatment demonstrated the benefit of changing the fracture surface wettability, leading to water transport into the downstream matrix block with no need to overcome the threshold pressure. Changes in fracture surface wetting preference were also confirmed visually in-situ by MRI imaging.

Polymers exhibit non-Newtonian rheological behavior, such as in-situ shear-thinning and shear-thickening effects. This has a significant impact on pressure decline signature as exhibited during Pressure Fall-Off (PFO) tests. Therefore, applying a different PFO interpretation method, compared to conventional approaches for Newtonian fluids is required.

This paper presents a simple and practical methodology to infer the in-situ polymer rheology from PFO tests performed during polymer injection. This is based on a combination of numerical flow simulations and analytical pressure transient calculations, resulting in generic type curves that are used to compute consistency index and flow behavior index, in addition to the usual reservoir parameters (kh, faulting, etc.) and parameters relating to (possible) induced fracturing during injection (fracture length and height). The tools and workflows are illustrated by a number of field examples of polymer PFO, which will also demonstrate how the polymer bank can be located from the data.

This paper presents an overview of the reservoir requirements regarding thedevelopment of the Marlim 3-Phase Subsea Separation System - SSAO (for theterms in Portuguese). Produced water re-injection (PWRI) in the reservoir insuch scenario is a challenging task, regarding the well injectivity maintenance(SSAO-treated produced water suspended solids and oil content, sub-sea andsub-surface facilities materials compatible with the produced watercorrosiveness), geomechanical effects, and biogenic reservoir souringcontrol.

Lessons learned from previous PWRI tests and the implications of somealternatives to the subsea separation and re-injection systems are reported.This work comprehends also the definition of chemicals applyed to preventundesirable effects: a bio-dispersant (to avoid biocorrosion and biofouling inthe re-injection system) and a nitrate salt (to oppose biogenic reservoirsouring potential). Relevant operational aspects are mentioned as well, fromchemical injection to the monitoring of both solid particles and oil dropletscontents in the re-injection water stream.

Summary

Our objective was to study foam flow in fractured, oil-wet carbonate rocks and determine if foam may be a viable enhanced-oil-recovery (EOR) agent in such reservoirs. We present experimental results in fractured carbonate rock and show effects of wettability on oil recovery when using foam. Oil recovery by water, surfactant, or gas injection exhibited low recovery, less than 10% of original oil in place (OOIP). Oil recovery during injection of pregenerated foam was improved significantly, with up to 78% of OOIP produced. Foam reduced the gas mobility in the fractured rock, increased differential pressure, and diverted flow into the oil-saturated matrix. However, a significant amount of foam injection was required for the additional oil recovery. Generation of foam in-situ was weak in the smooth-walled fractures, and no fluid diversion from the fractures with additional oil recovery was observed. On the basis of the experimental results, mechanisms for foam collapse in the fracture are discussed and possible steps to improve recovery are outlined.