74th EAGE Conference and Exhibition incorporating EUROPEC 2012

Fractured reservoirs are characterised by a large difference in permeability of the fracture and matrix system. Usually, the matrix contains the bulk of the oil while the fractures are the flow paths. These characteristics are challenging for projects aiming at increasing hydrocarbon liquid recovery from gas condensate fields by gas injection. While in fractured oil reservoirs, capillary forces (imbibition) or gravity forces can be utilised to improve oil recovery, for gas injection into gas condensate reservoirs, these forces are less important. The recovery mechanisms were investigated using the properties of a rich gas condensate field in the Middle East. A fine grid sector simulation model was created in which the fractures and matrix were introduced explicitly. Without taking diffusion into account, the injected gas breaks through at the producer very fast. The concentration in the produced gas is closely linked to the effective permeability of the fracture divided by the effective permeability of the matrix. However, taking diffusion into account, the increase in injected gas concentration is much slower. The speed of the increase (for the same pore volume injected) depends on matrix porosity, velocity of the front, fracture spacing and permeability contrast. The molecules of the injected gas are diffusing into the matrix while the components of the reservoir gas are diffusing towards the fracture. The various components have different diffusion coefficients. Dependent on the injection gas, the dew point pressure in the matrix can be reached (despite the reservoir pressure being constant) and condensate drops out. Hence, the condensate recovery depends on the injected gas. The results of the study show that neglecting diffusion in fractured reservoirs can result in errors in the condensate recovery of more than 50 %. In addition, the shape of the condensate recovery curve will be incorrect if diffusion is not accounted for.

When newly drilled oil and gas wells fail to reach the expected production levels, near-wellbore damage may have resulted from fluid incompatibility, poor fluid/rock interaction and/or mechanical damage. These problems may also occur during remediation or stimulation operations if the treatment fluid is not properly designed. The main formation damage mechanisms that lead to these problems are in-situ emulsions, wettability changes, water blocks and scale formation. It is recognized that such reservoir damage can be removed or prevented using microemulsion technology which leads to more productive oil and gas wells. The challenge is to design and select an optimized microemulsion system based on the reservoir conditions, such as the bottom-hole temperature and the composition of the crude oil, formation water, and the drilling and completion fluids. A well designed treatment fluid should provide ultra-low interfacial tension, high oil solubilization and complete compatibility of all fluids it encounters. The selection of the optimum formulations for specific applications requires a systematic study of the phase behavior of brine-surfactant-oil systems as a function of temperature and its final composition, which includes the salt, surfactants, co-surfactants and an optional acid. This paper provides a comprehensive discussion of the phase behavior obtained with the brine/surfactant/oil systems used in microemulsion formulations for formation damage prevention and removal. Laboratory tests results and field applications in open-hole and cased-hole completed wells have proven that the microemulsion treatment fluids are successful in the field if there is a systematic analysis of phase behavior that identifies and defines the treatment fluid phase boundaries.

The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996. Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline formation testers for the following reasons: - Severe depletion causing differential sticking - High temperatures (160CB0C) at the limit of tool electronics - Low permeability - Fractures and breakouts impacting seal success This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data to determine seal success and probe and packer influence, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects. While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Post-run wireline petrophysical data were gathered to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts. This novel approach resulted in 100% seal success, >60% improvement. Four days of rig time were saved, and the required data were obtained.

The growing demand for oil has emboldened producing companies to reenter old wells to drill laterals to further improve productivity and recovery. This requires reevaluating the water saturation. Successes in reservoir saturation monitoring petrophysical analysis have increased the confidence to drill sidetracks in watered wells that have bypassed oil potential. Several techniques can be used to perform the analysis. The Pulsed Neutron Log is one of the most popular. Slim logging tools allow running the surveys without having to pull out the production string. Under the right conditions, Pulsed-Neutron Capture logs can be run periodically in the time-lapse mode to monitor changes in water saturation, and movements in the oil-water contact and gas-oil contact. The wellbore environment might change between runs and this can complicate the analysis. For example, the borehole fluids can be different: gas, oil or brines of varying salinities. Also, changes in the downhole completion hardware would require running the logs in single or multiple strings. One has to be cognizant of all these environmental effects and appropriately correct for them to obtain the true formation properties, and to make comparisons between runs in the time-lapse analysis. Different vendors use different correction schemes. In this paper we will discuss case studies with a methodology from one service company that uses the forward modeling approach, which relies on first characterizing the tool response in a known environment. The paper will comment on the advantages and disadvantages of this technique, in particular, when the downhole conditions deviate from the characterized environment. Alternatives will be proposed to get the best possible results, based on a study conducted by Saudi Aramco. Finally, we will present some examples in Saudi Arabian wells where the computed capture cross section and neutron porosity were successfully corrected in challenging conditions.

The Eagle Ford Formation (EF) is a marl deposited during a highstand on a broad shelf along the paleo-Texas coast. It is thickest in the Maverick Basin, a small sag related to crustal thinning. Datasets were collected including core, cuttings, chemostrat, biostrat, and well logs. From the core and cuttings, core CT scans, thin sections, SEM images, FIB-SEM volumes, and XRD/XRF tables were acquired. The purpose of the data was to understand EF depositional processes and rock textures, and to create a predictive model for reservoir properties. The regional EF study began with correlation of 400+ logs. The correlation involved a sequence stratigraphic framework (SSF) based on log character and refined with ash correlations, biostrat and chemostrat. Texture seen in core, core CT scans, and the SEM/FIB-SEM work was compared to the SSF. These data gave insights into patterns of fluctuating oxygen and energy levels which were then included into the depositional model (DM). The DM shows regional patterns of composite parasequences in which properties such as TOC, porosity, carbonate content and rock texture are predictable. SEM/FIB-SEM images show that pores in the EF are mainly intergranular or within organic matter (OM), and that the structure of OM pores is related to maturity level. Using the SSF, reservoir properties can be predicted along the EF trend: cycles of EF with good reservoir properties can be mapped with respect to hydrocarbon fluid zones to yield risk maps. By understanding how and where different parts of a parasequence stack you can better predict sweet spots for well productivity, both geographically and stratigraphically. Each unconventional play is unique; what works for reservoir characterization and risk mapping in one is not always applicable to another. It is important, then, to document which strategies work in each play.

Unconventional gas resources from low-permeability formation, i.e., tight and shale gas, are currently received great attention because of their potential to supply the entire world with sufficient energy for decades to come. In the past few years, as a result of industry-wide R&D effort, progresses are being made towards commercial development of gas and oil from such unconventional resources. However, studies, understandings, and effective technologies needed for development of unconventional reservoirs are far behind the industry needs, and gas recovery from those unconventional resources remains low (estimated at 10-30% of GIP). Gas flow in low-permeability unconventional reservoirs is highly nonlinear, coupled by many co-existing, processes, e.g., non-Darcy flow and rock-fluid interaction within tiny pores or micro-fractures. Quantitative characterization of unconventional reservoirs has been a significant scientific challenge currently. Because of complicated flow behavior, strong interaction between fluid and rock, the traditional Darcy law may not be applicable for describing flow phenomena in general. In this paper, we will discuss a general mathematical model and use both numerical and analytical approaches to analyze gas flow in unconventional reservoirs. In particular, we will present analytical solutions of incorporating Klinkenberg effect, non-Darcy flow with threshold pressure gradient, and flow behavior in pressure sensitive media. We will discuss the numerical implementation of the mathematical model and show applications of the mathematical model and solutions.

Description Solvent injection has been recently considered as an efficient method for enhancing oil recovery from fractured reservoirs. If the mass transfer was solely based on diffusion, oil recovery would have been unacceptably slow. The success of this method therefore depends on the degree of enhancement of the mass exchange rate between the solvent residing in the fracture and the oil residing in the matrix. A series of soak experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. In a soak experiment, a porous medium containing oil is immersed in an open space containing the solvent to simulate the matrix and the fracture respectively. We use a CT scanner to visualize the process. The experimental data are compared with a simulation model that takes diffusive, gravitational and convective forces into account. Application For oil wet conditions, injection of a liquid (waste) solvent can be considered as a possible alternative for recovery from naturally fractured reservoirs. In the absence of interfacial tension no residual phase trapping occurs. Gravity enhanced transfer leads to practical recovery rates. Results, Observations and Conclusions The initial stage of all experiments can be described by a diffusion-based model with an enhanced C"effective diffusion coefficientsC". In the second stage enhancement of the transfer rate occurs due to the natural convection of solvent in the fracture and its effect on the flow in the matrix. The experiments can be quantitatively mimicked by numerical simulations. We find that transfer rates depend on the properties of the rock, solvent and oil. Technical and economic aspects are further discussed in the paper. Significance The interaction between matrix and fracture is visualized for solvent flooding by means of X-ray computed tomography, which can be used to validate theories of enhanced transfer in fractured media.

The Issaran field located200 km east of Cairo-Egypt, is a heavy oil reservoir.The oil is of 8-12 degree API with viscosity of 4000 cps at standard conditions. Productivity of the wells has sharply declined due to increase in water cut and increase in the formation skin value. The problem is attributed to the heterogeneity of the reservoir together with presence of fractures which is causing poor sweep efficiency plus the accumulation of hydrocarbon deposits. The major challenge to remedy this situation was; Not only the creation of new extended flow channels, accurate placement of the treatment, diversion within the reservoir, and to provide sustain production increase but also the flow and the production of oil through the newly formed wormholes. A new innovative approach using a combination of acid based treating fluids and steam were used. Acid in combination with unique chemical diverting agent plus selective placement mechanism succeeded to open new production horizons and stimulate the existing one. The Addition of Steam has succeeded in reducing the viscosity and increasing the mobility of oil, and also in providing pressure support to the reservoir achieving further increase in the benefits of the acid stimulation. The results of the treatments carried out so far have provided a new dimension in the enhanced recovery process of the heavy oil. This paper explains the design, execution, evaluation and the recommended way forward of this world first acid & steam production enhancement initiative for the reservoir enhanced recovery process.

Time-lapse (4D) seismic attributes can provide valuable information on the fluid flow within subsurface reservoirs. This spatially-rich source of information complements the poor areal information obtainable from production well data. While fusion of information from the two sources holds great promise, in practice, this task is far from trivial. Joint Inversion is complex for many reasons, including different time and spatial scales the fact that the coupling mechanisms between the various parameters are often not well established, the nature of the required model updates is localized, and the necessity to integrate multiple data. These concerns limit the applicability of many data-assimilation techniques. Adjoint-based methods are free of these drawbacks but their implementation generally requires extensive programming effort. In this study we present a workflow that exploits the adjoint functionality that modern simulators offer for production data to consistently assimilate inverted 4D seismic attributes without the need of re-programming of the adjoint code. Here we discuss a novel workflow which we applied to assimilate production data and 4D seismic data from a synthetic reservoir model, which acts as the real - yet unknown - reservoir. Synthetic production data and 4D seismic data were created from this model to study the performance of the adjoint-based method. The seamless structure of the workflow allowed rapid setup of the data assimilation process, while execution of the process was reduced significantly. The resulting reservoir model updates displayed a considerable improvement in matching the saturation distribution in the field, as well as a vast improvement in predictive capacity. This work was carried out as part of a joint Shell-IBM research project.

Automatic history matching may be used to condition reservoir simulation models by including time-lapse seismic data. Stochastic optimization algorithms are used to perform a good search of the parameter space and to ensure proper determination of the best models. These approaches can require many thousands of simulations for large dimensional problems. Divide and conquer is an assisted history matching approach that enables deconvolution of the parameters so that they can be searched more efficiently and also leads to better uncertainty analysis. We present an application of this approach to the Nelson field. Nine years of production history data were used along with seismic baseline and monitor surveys. Localised variations were made to permeability and net:gross. We were able to divide the reservoir model into separate parameter regions as a form of localization by combining experimental design and proxy model analysis. The former enabled insignificant parameters to be discarded. The latter showed that each region could be treated as a separate history matching sub-problem which was solved simultaneously using an adapted genetic algorithm. We found that a forty-two dimensional problem could be reduced to a combination of three 9D problems and a 3D problem due to the spatial deconvolution of parameters and misfits. An improved match was obtained for the production and seismic data. Compared to a full stochastic search of the parameter space, the number of models was several orders of magnitude smaller. Further, improved uncertainly analysis was made possible resulting in better forecasting. An improved match to reservoir models leads to better confidence in their prediction and thus they can be used more effectively in reservoir management. The method presented here improves the match and retains the benefits of stochastic searching without the penalty of requiring an impractical number of simulations.