In the western desert region of Egypt, previous propped multiple-fracture treatments were performed using conventional methods (i.e., perforate, frac, set mechanical/zone isolation, and repeat cycle). Although the resulting treatment efficiency was satisfactory, other methods were being considered to help reduce cost and improve production performance. Also, it was desired to decrease total operational time, which would further impact economics (rig time, production delay, etc).In an attempt to improve production response, fracturing designs in the El Fadl field in the western desert went from a standard three-stage design up to as much as a six-stage design to more effectively stimulate the pay zones. A careful review of the field and operations suggested possible benefits from implementing the pinpoint method for hydraulic-fracturing treatments. It was, however, not a simple case of just applying a hydraulic-fracturing treatment to every potential zone, but required proper well screening, thorough log analysis, calculating and validating mechanical rock properties, and enhanced 3D fracture modeling to achieve a successful campaign.A pinpoint method for stimulation was implemented to perform multistage jobs at reduced costs. As the stage count per well was increased, production response and economics were improved. Both treatment design and staging design with this fracturing technique continue to be further refined as performance and statistical analysis of previous design changes are completed.This paper discusses a pinpoint method for frac treatment and the methodology applied on a recent well. Differences in job execution that will be discussed include: using a hydrajet perforating mechanism instead of conventional casing-gun perforation, time-consumption reduction, analysis of vertical-fracture coverage per potential zone, and cumulative production response from the different designs tested. This could serve as guidelines for other operators who might be facing similar challenges in the North Africa region and elsewhere.
The Aruma formation is the shallowest hydrocarbon-bearing reservoir in the Bahrain field. It contains heavy oil and bitumen irregularly distributed in fractured and vuggy carbonate rocks, making reservoir characterization and hydrocarbon production particularly challenging.
Bahrain field is an asymmetrical anticline trending in the North South direction. The sedimentary column extends from Cambrian Saq Sandstone to the Miocene reefal deposits, exposed on the surface.
Due to the complex geological nature of naturally fractured reservoirs (NFRs), their development is often associated with a lot of challenges, especially when it comes to improved oil recovery (IOR)/enhanced oil recovery (EOR) processes, where certain fluids are injected into the reservoir with the aim of increasing the recovery factor. If a large enough contrast in permeability between the rock's matrix and the fractures exists, which is often the case, fractures will dominate the flow, leading to a poorly processed matrix and eventually a poor recovery factor. The Rubble reservoir is one of the shallowest reservoirs in the long-producing Bahrain field that was discovered in 1932 as the first oil discovery in the Gulf Cooperation Council (GCC) region. With the majority of oil in place categorized as heavy oil, it was decided that a steam pilot would be implemented in 2011. Steam piloting in the Rubble reservoir has gone through multiple stages since 2011, and different thermal recovery processes have been tested using vertical, deviated, and horizontal wells. The initial pilot tested cyclic steam stimulation (CSS) using high-pressure steam injection and low-pressure production in vertical wells, which was successful in mobilizing oil from the low-permeability Rubble reservoir. Based on the initial technical success, the CSS pilot was expanded to 17 additional wells drilled on three well pads in different parts of the field with different reservoir properties. The CSS expansion pilot also mobilized oil from the reservoir. Subsequently, continuous steam injection and offset oil production were attempted in two of the steam pilot pads. CSS was also attempted in horizontal wells; however, although oil was mobilized, the produced rates and volumes were not enough to have a low steam/oil ratio (SOR). These efforts ultimately led to the forced imbibition (FIM) pilot. In this current pilot, steam is simultaneously injected into three parallel, closely spaced horizontal wells and then produced simultaneously using large pumping units to reduce the bottomhole pressure to a minimum. Results have been encouraging, with SORs of less than 4 barrels of steam per barrel of oil (bs/bo). FIM has proved to be the most promising steam EOR process attempted in the Rubble reservoir. This paper examines the results of the Rubble steam pilot stages, highlights the challenges faced in each stage, and presents our evolved understanding of the physical processes involved as the pilot progressed.
A customized thermal enhanced oil recovery (EOR) process is being piloted in the heterogeneous, tight and heavily fractured Rubble formation of the Bahrain Field to overcome reservoir drainage challenges. High viscosity reduces the oil's mobility in the low permeability matrix where most of the oil resides. Steam is used to increase the matrix oil's mobility. However, due to the large contrast in permeability between the matrix and fracture systems, injected steam tends to preferentially flow into the highly permeable fractures, bypassing the tight matrix and resulting in poor thermal oil recovery. Extensive fracturing also increases the risk of pre-mature steam breakthrough by connecting injectors to producers. On the other hand, due to the very low matrix permeability, it would be difficult to inject enough volumes of steam to sufficiently heat the matrix and reduce oil viscosity if fractures did not exist. Such a dilemma highlights the need to think of engineering designs that would manage the presence of fractures or utilize them as pathways that efficiently deliver heat to the matrix; this is when the Forced Imbibition (FIM) concept evolved. The concept implies injecting large slugs of steam at high pressure simultaneously into closely spaced horizontal wells that are in direct communication through the fracture system, allowing the heat to soak into the matrix, and then producing all the wells together. Essentially FIM is a high pressure multi-well "huff-and-puff". The first FIM test was conducted in late 2014 and steam-oil ratios (SOR) of 5 bs/bo (barrels steam per barrel oil) or less were achieved in all 4 cycles. This paper describes the FIM test concept and design, discusses the inputs into reservoir simulation, and examines the actual pilot results.
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