How can you use formation evaluation to increase recovery?

Understanding reservoir characteristics is like surveying the terrain before a journey, assessing porosity, permeability, and geological formations. This informs the plan of action in oil and gas recovery. Planning involves strategizing extraction methods based on this understanding—like charting a course for optimal recovery through well placement and drilling techniques. Recovery is the goal, analogous to reaching a destination. Success hinges on the accuracy of the initial assessment and the effectiveness of planned actions. It's a dynamic process, requiring continuous monitoring and adjustments for efficient hydrocarbon extraction.

para lograr la mejor recuperación posible, es necesario contar con la mayor cantidad posible de datos de las capas de interés, del proceso de perforación, de pozos vecinos, entre muchos otros. es necesario invertir y hacer lo mejor en el pozo para maximizar la explotación del recurso de forma segura, sin dejarlo a la suerte.

The effective use of formation evaluation throughout the life cycle of an oil and gas reservoir allows for informed decision-making, optimization of production strategies, and the implementation of techniques that can lead to increased hydrocarbon recovery. This integrated approach contributes to the economic and sustainable development of hydrocarbon resources.

Formation evaluation can increase recovery by providing insights into reservoir properties. Analyzing data from well logs, cores, and seismic surveys helps understand rock and fluid characteristics. This information guides reservoir modeling, enabling accurate estimation of reserves and identification of optimal production techniques. By leveraging formation evaluation, operators can tailor enhanced oil recovery (EOR) methods, adjust well completion designs, and implement reservoir management strategies. This enhances the overall recovery factor and maximizes hydrocarbon extraction from the reservoir.

First of all understand what was the depth reference, be it measured depth from KB or ground, or from sea level. Would well deviation need to be considered for vertical depth? Would cable stretch need to be considered for depth correction, or depth shift to drilling pipe based depth? As to the reading of well log, would you need normalization or correction for wellbore effect of drilling fluid effect? Keep in mind that well log measurements has vertical resolution or averaging, and depth of investigation from the wellbore into the formation.

A successful coring job and recovery of core samples to surface is valid for both fluid and rock characterization and this will ensure accuracy of gathered data hence contributing for better simulations and will reflect on productivity of the field.

As drilling typically involves drilling fluid, core sample will be flushed by drilling fluid to various degree. Fractures could be created during drilling. Unless full core is used, smaller size core samples would be drilled for actual analysis. For very tight formation, measurements are done on crushed samples. Cleaning and drying of the samples will alter the samples to various degree, especially when clay content is significant. Porosity measurements are typically more accurate, especially when clay content is low and the rock is consolidated.

Well Testing is a dynamic formation evaluation method that can be divided into three types: - Pressure transient test (i.e. pressure build up & draw down) - Periodic productive test - Deliverability test Typical dynamic well testing called DST which involves lowering a temporary test string (tubing) down the wellbore to assess the properties of the formation. DST allows conducting different functions: - drawdown & buildup test - sampling - pressure & temperature surveys

Production testing is having fluids produced, with or without casing, with or without downhole measurements, with or without fluid reaching the surface. Production testing is the actual proof that certain types of fluid could be produced, assuming it is not all drilling fluid. False information may include bad seal and formation damages. With large enough volume produced and long enough time, uncertainty would be lowered.

Ideally if drilling underbalanced you will be sampling formation fluid while drilling, without formation damage. As formation fluid is diluted by drilling fluid, accurate sampling and measurement should be used when produced volume is small.

Dynamic well testing (DST) is a typical method used to calculate the total skin from pressure transient analysis ( build up and drawdown tests).

Adding to what has been mentioned, another new innovation is: Dual zone drill-stem tests (DSTs), using A single DST string with wirelessly- activated downhole tools and flexible control options to modify the test program on the fly, based on real-time data analysis and performance of each zone. This well test technique can still achieve multiple critical reservoir characterization objectives by testing each zone individually, performing a Vertical Interference Test and allowing to test a selected zone without flowing it to surface.

In any large development project, one of the reservoir parameters with the highest impact on NPV is average or typical permeability to the produced fluids. Often, multiple methods of measuring or deriving permeability are utilized during both exploratory and development drilling. Less frequently, post-completion pressure buildups or pressure transient analyses are employed to refine permeability estimates. A critical step, then, involves developing calibration factors for the various logging, DST, and sampling operations, so that these can be related to the pressure buildup and pressure transient analyses. Development of these constants can be invaluable with respect to both cost control and boosting confidence in forward modeling.

Using formation evaluation in tandem with strategic well placement technique (Geosteering) is a powerful approach to enhance hydrocarbon recovery. Analyzing reservoir characteristics and data helps identify optimal locations for well placement. By targeting high-porosity and permeable zones, you can maximize reservoir contact and improve production efficiency. This integrated approach aids in placing wells in the most productive areas, contributing to increased hydrocarbon recovery and overall field performance.