Hydraulic fracturing has been an integral part of the development of two gas/condensate fields in Oman. The producing reservoirs are quite thick (160-190 m) and highly laminated, so fracture height growth and vertical coverage are key issues. High production rates and condensate production also mean that non-Darcy flow in the fracture is important.There are significant variations in permeability and depletion (following several years of production) within the reservoir, which makes any analysis more complicated. There has been an evolution in the fracturing strategy in terms of the number of treatments pumped per well (going from 1 to 5 fractures), the size of proppant used (12/20, 16/30, 20/40) and the size of the pad volume (75-350 m3).

Questions existed about the performance of the fracture stimulation treatments, particularly about whether the effectiveness of the fracture stimulations was decreasing over time, as one performance indicator showed. In order to answer these questions, a study was performed to evaluate the individual fracture performance based on the post-frac production logging data (PLT) which gave a production rate for each fracture in the well.

In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages.

While successful development of the northern part of the Minami-Nagaoka reservoir could significantly impact Japan's domestic natural gas production, successful proppant placement in this field has proved extremely difficult in the past (1-2). During two propped fracture treatments pumped more than a decade ago, treatments failed miserably with only about 20% of the designed proppant placed before job termination due to premature screen-outs. These treatments exhibited net pressures up to 4,000 psi before pumping any proppant - the highest net pressure level that we have ever observed, indicating extremely complex fracture growth. Post-frac evaluation confirmed that proppant placement problems mainly occurred due to simultaneous propagation of very narrow multiple hydraulic fractures. Detailed pressure build-up and production test analysis confirmed the diagnosis of narrow multiple hydraulic fractures, which resulted in extremely poor (and vanishing) propped fracture conductivity and non-economic gas production.

This paper provides a case history of hydraulic fracture completions in horizontal wells in the South Arne Field, Danish North Sea (9500 ft TVD, chalk formations).1 The first three propped fracture treatments attempted in the South Arne Field "screened-out" very early in the design due to excessive fracture complexity and fluid leakoff. A detailed study of the rock mechanical properties, wellbore stress & fracture initiation characteristics, far-field stress regime & fracture orientation, and fluid leakoff behavior was integrated with fracture modeling studies to evaluate this problem.2 These studies were used to improve the fracture treatment strategy for future wells, resulting in essentially 100% success placing the designed proppant volumes and achieving aggressive tip screen-outs (TSOs) on over 60 fracture treatments.

This paper summarizes the initial fracture treatment problems and provides a detailed discussion of fracture modeling and design issues, mini-frac analysis procedures, and the mitigation and evaluation of fracture complexity.

This paper presents a detailed case history of the evolution of fracture technology in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft with permeability ranging from 0.01 to 1 mD. The first three wells drilled in 1996-97 were fracture stimulated, but only one of the three treatments was successful. Three more wells were drilled in 1999 and significant improvements in completion and hydraulic fracture technology were implemented. This paper presents a comprehensive data set, which includes the evaluation and integration of pre- & post-fracture well tests and log data with detailed fracture modeling analyses to understand and improve fracture performance in this complex environment.

This paper presents the results of a study conducted to improve hydraulic fracturing and field development in the Arcabuz-Culebra Gas Field in Mexico. Hydraulic fracture mapping was performed on four stimulation treatments using a combination of tiltmeters (surface and downhole) and microseismic imaging. Fracture mapping was complimented by 3-D fracture modeling and geomechanical modeling. Data analyses resulted in recommendations regarding well positioning and hydraulic fracture design.

The technology of hydraulic fracturing is faced with a conceptual transition from a classical single-planar fracture to a tortuous fracture network and simultaneously propagated multiple hydraulic fractures. This new concept is applied to analyses of two propped fracture treatments conducted in a volcanic formation. In both cases, the productivity was doubled, but the treatments themselves were unsuccessful, experiencing extremely high net fracturing pressures and very premature screen-outs.

The classical concept of a single-planar fracture could not explain either the fracturing-pressure behavior or the post-frac production rate/pressure. Adopting a multiple-fracture geometry resolves this problem. The fracturing pressures are successfully simulated, and the resultant fracture geometries are consistent with both the premature screen-outs and the post-frac production performances. Combined analyses of fracturing pressure and subsequent production performances firmly confirm the creation of multiple fractures in a volcanic formation.

We analysed the influence of well deviation on hydraulic fracture treatments in gas bearing Bunter formations, offshore Holland. The reservoir permeability ranged from 2 to 20 mD, which was relatively high for stimulation. Analysis of the pressure records of injection tests and treatments indicated low net fracture pressure and contained fractures. Most treatments ended in wellbore screen-out, giving a high fracture conductivity, especially near the wellbore. The success of the treatments was due to by-passing of a severe skin as well as stimulation of the formation. Also, the well was connected to additional flow units, evidenced by a substantial increase of the permeability (obtained from well tests) after the treatments. In a deviated well we observed gas entry into a small section of the perforated interval. However, there was no indication for a reduced performance of wells with a large deviation compared to the performance of vertical wells.