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.

Today, geological and hydrodynamic models are widely used for efficient development and monitoring of oil and gas fields. These models are designed to handle a wide range of tasks. Their reliability directly affects the quality of results and any uncertainties should, therefore, be minimised. The use of additional techniques can enhance the reliability and predictive ability of the models and minimise risks. This paper describes how integrating accurate description of flow geometry with reservoir properties and reservoir models to achieve this objective and, to generate a more reliable picture of the reservoir performance. The study included running HPT-PLT-SNL high precision logging tools, and covered a pilot area with five wells in a Cretaceous carbonate reservoir. The wells were completed in the lower and tighter Sub-reservoirs units F1 and F2 and the objective of this pilot is to identify the flow geometry in wells' neighborhood, particularly identify channeling, fracture flows or other types of communication. The objective of the associated simulations and study is to correlate the acquired and interpreted data with those suggested by simulations and come up with consistent description of reservoir flow geometry within the pilot pattern.

The most challenging point of this flooding campaign is the complexity of the reservoir in this area. The flooding pilot sets the targets for tight Sub-reservoir carbonates Unit F1 and Unit F2. It's important to know if the flow ensues exactly within these units and does not communicate with other reservoirs with better permeability.

Objective Description

The subject study, Abu Dhabi's Cretaceous carbonate reservoir is combined of five sub reservoirs and they are as shown in figure 1 below, Units F5, F4, F3, F2 and F1. All five sub-reservoirs are of different characteristics in terms of permeability, porosity, rock type, etc. (As shown in Table 1 and Fig. 1). Those sub-reservoirs are lying on top of each others almost without any barriers between them; accordingly, this might provoke the water/gas to cone/slump to/from the concerned reservoirs.

A project is in progress to decide on the development of the tight reservoir (F1+F2) to further improve the poor sweep efficiency, increase the oil recovery in both reservoirs, water slumping, inefficient flank pressure support, vertical permeability between sub-reservoirs, assess the impact of injecting in Units F1+F2 on fluxes across Units F3, F4, F5 and F1 and F2, determine pressure support due to injection in Units F1 and F2, and overlying units.

Clair Ridge will include the first offshore deployment of BP's reduced salinity LoSal^® enhanced oil recovery (EOR) water injection technology. Over the last ten-years, there has been significant growth in the evidence supporting the use of low salinity water injection as a viable EOR process. BP, by using its LoSal EOR technology, has shown that incremental increases in oil recovery can be achieved across length scales associated with core flood experiments (inches), field-based single well chemical tracer tests (feet) and field trials (inter-well distances). This paper discusses the process undertaken by the Clair Ridge project in getting LoSal EOR adopted as a day one, secondary waterflood.

Confirmation and quantification of the LoSal EOR potential at Clair Ridge began in 2006 with completion of a series of core floods using three reservoir rock types. However, it was recognised that as a green field development single well chemical tracer tests or field trials were not possible ahead of sanction. Therefore, confidence in the materiality of recoverable oil by using LoSal EOR was built through integration of core flood data into reservoir simulation studies focused on a thorough investigation of the subsurface, produced water disposal and reverse osmosis operability uncertainties. In parallel, scoping facilities studies were completed to provide cost, weight and footprint estimates for inclusion of a 145 mbd RO plant on the platform. Finally, and critical to the success of this project was early and open partner engagement in LoSal EOR evaluation.

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.

Nowadays, as the deep gas reservoirs in Daqing are explored, the complex volcanic reservoirs have been the major reservoirs in deep natural gas exploration and production. The reserves of volcanic gas reservoirs take up 88% of the total gas reserves. However, the deep complex gas reservoirs may cause heavy pollution during the drilling completion, and some of the barriers between target zones of the wells are very thin, leading to a poor stability. Additionally, because of the complex water/gas relations in the formation, such as appearance of bottom water and water and gas sharing the same formation in some wells, the fracturing operations will induce water channeling. All these facts may cause the failure of the fracturing operations.

Especially, when the fractured formation is close to the water/gas interface, the fractures will easily extend into the water layer. The existence of water in the gas wells directly leads to the reduction of production and recovery rate of the gas reservoirs, or even kills the gas reservoir in the worst cases. For these types of gas wells, acidization technology is a promising solution. It not only avoids the pollution near the wells of volcanic formation, but also chemically dissolves the fillings in the fractures and pores, improves formation seepage flow environment, increases fluid mobility, and finally optimizes the productivity. Acidization technology also has the advantages of low investment and quick payback.

This paper reports the volcanic reservoir acidization technology we developed. The lab test results show that this technology solves the problems of high erosion rate of the oil strings under high temperatures (125-160 degree of Celsius). The acidization technology is applied in three wells, and the productivity of those increases profoundly.

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.

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.

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.

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.

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.