ATCE: EOR Chemical and Thermal Applications Abstracts

SPE Technical Papers: EOR Chemical and Thermal Applications

Technical papers, referencing CMG software, presented at the 2016 SPE Annual Technical Conference & Exhibition, Dubai UAE

Multi-thermal Fluid Assisted Gravity Drainage Process to Enhance the Heavy Oil Recovery for Post-SAGD Reservoirs
Paper: SPE 181479

Multi-thermal fluid is a new type of heat-carrier proposed in recent years for the EOR process in heavy oil reservoirs. Compared with the conventional saturated-steam injection process, multi-thermal fluid injection technique combines the multiple advantages of im/miscibility gas injection and thermal recovery. In this paper, based on the multi-thermal fluid injection process and the conventional steam-assisted-gravity-drainage (SAGD) process, a new thermal gravity-drainage process, multi-thermal fluid assisted gravity drainage (MFAGD) technique is proposed to enhance the heavy oil recovery for the post-SAGD reservoir. From the dimensionless scaling criterion of gravity-drainage process, two 3D gravity-drainage experiments (SAGD, SAGD-to-MFAGD) are firstly conducted to explore the EOR mechanisms of multi-thermal fluid in heavy oil reservoirs and oil sands. Subsequently, numerical simulation has been performed to match the experimental measurements. Then, from the scaling criterion, these lab-scale reservoir properties are converted to field-scale. Thus, a field-scale numerical model is developed. From this field-scale numerical model, the difference of SAGD process and MFAGD process are discussed. The reservoir adaptability of MFAGD process are investigated, and the operation parameters are numerically optimized. […] This paper further deepens the understanding of the EOR mechanisms of multi-thermal fluid injection process in heavy oil reservoirs and oil sands. The proposed MFAGD process will be a significantly potential EOR method for the post-SAGD reservoir.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

An Improved Methodology for Simulating Oil Recovery by Carbonated Water Injection: Impact of Compositional Changes
Paper: SPE 181630

Enhanced Oil Recovery by carbonated water injection (CWI) has recently attracted significant attention. The main advantage of CWI, compared to conventional CO2 flood, is that it requires small amount of CO2 and it can be readily applied to oil fields with on-going or planned waterflood. The challenge with CWI is numerical simulation of the complex compositional changes that take place as a consequence of the transfer of CO2 from CO2-enriched (carbonated) water to crude oil under reservoir conditions. We have recently reported that these compositional changes result in the formation of a new gaseous phase within the oil and become the dominant mechanism controlling the performance of CWI.

In this investigation, utilising the results of novel direct visualisation experiments, a new and improved methodology for simulating the performance of CWI has been successfully developed that is capable of reproducing the physical processes observed in our micromodel and coreflood experiments. The results of the history-matching exercises demonstrated that, to properly capture the underlying mechanisms of EOR by CWI, the phase behaviour and three-phase flow functions should be coupled in numerical simulation of the process. The results also revealed that the binary interaction coefficients between oil components and CO2 would control the extent of the gaseous-phase formation. Also, a relatively high value for critical gas saturation was obtained to history match the coreflood experiments, which was in agreement with the results of the direct visualisations experiments. Moreover, a variety of three-phase oil relative permeability functions were considered to replicate the movement of the gaseous-phase, which would be dictated by reconnection of the oil ganglia. The new phase formation outperforms other oil recovery mechanisms such as reduction of oil viscosity and oil swelling.

The results of the study help improve the accuracy of the numerical simulation of the oil recovery processes involving CO2 and carbonated water injection. This will in turn improve the quality of our reservoir performance predictions and the reliability of our economic calculations of these enhanced oil recovery techniques.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

Specific Procedure for an Offshore Chemical EOR One Spot Pilot in a High Salinity High Temperature Environment
Paper: SPE 181643

In 2014, Total performed a surfactant-polymer one spot pilot offshore to test the effectiveness of inhouse developed surfactant molecules to mobilize trapped oil. This paper describes the deployment of this pilot, as a key step of the derisking roadmap of chemical EOR under the harsh salinity and temperature conditions of Middle East carbonates. During several years of R&D and focused studies on this field of the Emirates, a surfactant polymer formulation has been developed able to achieve very low residual oil saturation at core level. The question of testing the formulation in the field has been addressed in parallel to the laboratory work, through extensive surface and subsurface integrated studies, in order to define which type of pilot would be the more suitable.

The paper addresses several aspects:

Pilot type selection from a geosciences point of view and versus objectives and information provided: where, how many wells, time response, cost
Monitoring needs: base line establishment, injection and production follow up,
Surface issues related to the pilot in this offshore context: injection and production top side facilities
Chemical logistics when part of the formulation is a R&D chemical, to be manufactured on purpose, and imported in due time, including the choice of premix versus on line mixing products
Management of a pilot as a project but still with the specificities of derisking and qualifying a technology on a mature field (from preliminary study to project execution)
Offshore concerns, with the added difficulty of a H2S environment

[…] The paper emphasizes how a strong project management, and headquarters/operational team collaboration allowed completing a safe and successful pilot, ultimately achieving ultra low residual oil at the one spot scale. The success of a pilot project is conditioned to the strict application of a rigorous methodology of study, validation, and execution, like any development project.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

SAGD Operation in Interbedded Sands with Application of Horizontal Multistage Fracture; Reservoir Engineering Aspects
Paper: SPE 181511

Steam assisted gravity drainage (SAGD) is a widely used thermal recovery method. During steam injection in interbedded sands, the portion of the deposits above the vertical permeability barriers is likely not recoverable with current practices. This paper examines the reservoir engineering aspects of using multistage fracturing in SAGD operations in interbedded sands such as IHS, where the vertical permeability barriers impede the gravity drainage process. […]

Through numerical simulation, a matrix of sensitivity cases was developed with variation of key parameters such as fracture permeability, fracture half-length, fracture spacing and orientation. It was shown that fractures with short half-length but high conductivity are required for the process to work. Using the sensitivity results, an optimum range for key fracturing parameters was determined. Furthermore, a dimensionless fracture conductivity criterion was used as a general design criterion. The issues around fracturing design and sand-shale geomechanics are presented in a separate paper.

The multistage fracturing technique in horizontal wells was first used in tight and shale gas plays, and different variations of the field execution of this technique are now widely available. To our knowledge, this work is the first detailed examination of the potential of multistage fracturing for improving SAGD in interbedded pays. It is shown that, if this technique can be combined with in-situ steam operations, some of the problems with steaming interbedded pays can be addressed. In particular, it is shown that the recovery can be substantially improved to be comparable to clean sands. However, the use of multistage fracturing in SAGD process also introduces unique execution challenges that require thorough analysis and design, which were the focus of the companion paper (Saeedi and Settari, 2016).

Interpretation and Analysis of Transient Sandface and Wellbore Temperature Data
Paper: SPE 181710

In this paper, we provide new analytical and semi-analytical solutions based on a coupled wellbore/reservoir thermal model to investigate the information content of transient temperature measurement made within the vertical wellbore across from the producing horizon or at a gauge depth above it during drawdown and buildup tests. Our investigation leads to new interpretation/analysis methodologies of sandface and wellbore transient temperature data based on temperature-derivative and straight line methods for estimating near wellbore and far field formation parameters. Slightly compressible, single-phase, and homogeneous infinite-acting reservoir system with skin effect is considered. […]

Results show that drawdown sandface temperatures are totally dominated by advection, whereas buildup sandface temperature data are dominated by conduction. Drawdown and buildup sandface temperature data exhibit two semilog straight lines; one at early-times reflecting the effects of adiabatic fluid expansion in the in the skin zone near the wellbore, whereas the late-time semilog straight line reflecting the Joule-Thomson effects and exhibiting the non-skin zone properties. For temperature measurements made at locations above the producing horizon, the wellbore temperature is strongle dependent upon distance above the producing horizon, geothermal gradient, and radial heat losses from the wellbore fluid to the formation on the way to gauge. Our results indicate that skin-zone properties seems very difficult to estimate from the drawdown and buildup wellbore temperatures unless the gauge location is not far from the producing zone. Buildup wellbore temperature seems mostly dominated by wellbore heat losses as compared to drawdown wellbore temperature data and hence cannot reflect the formation properties.