Borehole to Surface Electromagnetic (BSEM) technology was conceived in the former Soviet Union and fine-tuned by the Chinese Bureau of Geophysical Prospecting (BGP). Saudi Aramco recently deployed the first BSEM pilot test outside of China (Marsala et al., 2011). This paper describes a new world first innovative electromagnetic borehole to surface survey in a well completed with multiple casings. The objective was to deploy a single BSEM survey to map the oil-water distributions in two separate reservoirs. This BSEM survey was conducted in a mature Saudi Arabian oil field composed of two main naturally fractured carbonate reservoirs, separated by a thick nonpermeable zone. The Upper reservoir is prolific, while the Lower reservoir is relatively tight and highly fractured. The reservoir pressure data from the early production period confirmed communication between the two reservoirs through several large scale fractures crossing the nonpermeable zone. In the Lower reservoir, well log observations show a variable oil-water distribution. No direct measurements of fluid saturations are available in the inter-well areas. The BSEM survey was designed to fill this data gap. In June 2012, a very challenging BSEM field acquisition was successfully completed with zero downtime and no accidents, obtaining very good data quality. Electromagnetic (EM) signals were transmitted at multiple frequencies from four source locations placed in a single vertical transmitting well that cross through both reservoirs and received by more than 1,000 surface stations, located in a grid at distances up to 3.5 kilometers away from the transmitting well. Multidisciplinary teamwork and independent peer reviews are undertaken to guarantee the optimal benefit from this pioneering technology. The business impact is to increase recovery by maximizing sweep efficiency and optimize well placements. Introduction A state-of-the-art Borehole to Surface Electromagnetic (BSEM) survey has recently been acquired in a giant mature oil field located in the Eastern Province of Saudi Arabia. The production from this field has been primarily from two fractured carbonate reservoirs, Upper and Lower, which are separated by a 500 ft thick, non-reservoir limestone formation. The Upper reservoir is prolific throughout the whole field and its high rate producers have been responsible for the majority of the historic field production. The Upper reservoir performance, including waterflood fronts, has been very predictable, which have made it easy to identify well targets and plan successful new development wells, sidetracks and other well remedial action based solely on well data like production performance, inflow profiles and saturation logs. The Lower reservoir is oil bearing only in the southern part of the field. This reservoir has low matrix permeability with well productivities and inflow profiles controlled mainly by a complex fracture system. A comprehensive Lower reservoir development drilling program is currently ongoing to augment the reservoir production. Due to the complex fracture system, the Lower reservoir development drilling program has been prone to unpredictable well fluid saturation results. Another element of uncertainty is the presence of several large near vertical fractures creating communication with the significantly more mature Upper reservoir. In structural positions where the basal part of Upper reservoir has been swept by water, these vertical fractures create pathways for water gravity dumping from Upper to Lower reservoir. A further complication is that the actual locations of these fracture communication pathways are not always known, which at times results in well logs showing unexpected water bearing fractures and water imbibed matrix.

In contrast to near-wellbore conformance control applications, polymer gels are applied in injector wells for reservoir scale applications for in-depth fluid diversion (IFD). Novel gel systems include weak gels, sequential injection for in-situ gels, colloidal dispersion gels, preformed gels, and microgels. The objective of an IFD process is to modify the prevailing reservoir inflow profile by gel treating the reservoir to significantly reduce effective permeability of high permeability zones that would otherwise dominate the water uptake. The weak gels or gel particles are treated as a flowing fluid and are custommade for reservoirs with fractures or high permeability zones. The very weak gels form near the wellbore region, but continue to propagate into the reservoir. The gels eventually stop propagating deeper into reservoir due to the variation in pressure gradients and pore structures. The subsequent injection of fluids, water or chemical solutions, will redirect predominate flow paths to unswept reservoir zones, which improves oil sweep efficiency by waterflood (or chemical flood); thus, leading to enhanced oil recovery. The technology presents distinctive advantages to high-salinity and high-temperature reservoirs as compared to polymer flooding due to stability of cross-linked gel structures.This paper presents a state-of-the-art review of IFD technologies including weak gels, sequential injection for in-situ gels, colloidal dispersion gels (CDG), microgels, and preformed particle gels (PPG). Moreover, a solution to the challenges of IFD applications in high-salinity and high-temperature reservoirs is presented.

The common wisdom is that gravity methods have limited application in the oil industry although they have long been available. The main use of gravity has been for exploration purposes. 4D microgravity monitoring is another new promising gravity application to monitor changes of fluid contacts. Some successful 4D monitoring surveys have been conducted in the industry revealing that this technique is a proven technology in monitoring of gas-water contacts.This paper studies the ability of microgravity to capture movement of the injected water in a giant carbonate field. The oilwater case is more difficult due to the significantly lower density contrast as compared to the gas-water case. Monitoring water floodfront in the field is a key factor in applying successful reservoir management practices to maximize recovery and prolong the field life. The monitoring of inter-well fluids would characterize any pre-mature water breakthrough to allow planning and design of appropriate remedial well interventions. The current applied monitoring tools such as carbon-oxygen and resistivity logs can only detect fluids near to the wellbore due to their shallow radius of investigation. For the study field, 4D seismic cannot be used for fluid movement detection due to issues related to formation acoustics impedance and data quality.The study has shown that surface microgravity monitoring could successfully detect the inter-well fluid changes due to water injection with a high precision tool (0.01 microgal). It also shows that microgravity monitoring can capture water bodies located hundreds of meters away from the location of the 4D measurement.

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This paper presents an ensemble-based computer Assisted History Matching (AHM) of a real life carbonate oil field. The field-level reservoir pressures were matched with a fine-scale Dual-Porosity DualPermeability (DPDP) model spanning a long production history under primarily peripheral water injection pressure support. The well-level AHM workflow presented was validated with a DPDP high-resolution sector model of a fracture dominated carbonate reservoir. This sector model was ~17 million active grid cells with no application of simulation grid upscaling. The AHM workflow integrates probabilistic Bayesian inference using Ensemble Smoother with Multiple Data Assimilation (ES-MDA), which simultaneously assimilates the data and generates maximum a-posteriori updates of reservoir model parameters in a variance- minimizing update scheme. A detailed uncertainty matrix was built with ensemble of sensitivity scenarios, based on varying free water level, corresponding matrix porosity and the initial water saturation combined with geostatistical realizations of dynamic permeability derived from dynamic PLT logs and fracture characterization, where the varied parameters were the variogram attributes in terms of correlation length and geometric anisotropy. Five data assimilation iterations with ES-MDA method were required to achieve acceptable convergence and minimization of objective function, defined as a joint misfit of well-level static pressures and watercut for the key producing wells. Practical DPDP model simulation times were achieved through utilization of Massive Parallel Processing technology. This study presents the first ensemble-based approach to integrated reservoir modeling for a mature oil field with the objective to deliver geologically-constrained history matched models with better predictive value for production optimization and forecasting.