The Kraken field development was planned and executed through several batch drilling and completion phases to allow a review of each phase and incorporate the lessons learned in the next phase. All producers were drilled with an oil-based reservoir drilling fluid (OB-RDF). The lower completion with shunted sand control screens was installed in conditioned OB-RDF, followed by displacements to water-based fluids after the packer was set. Gravel packing was performed with a visco-elastic surfactant fluid, and a breaker treatment was spotted across the open hole prior to isolating the open hole with a fluid loss control valve. This paper discusses the design, execution and evaluation of the lower completion phase for the development of the Kraken field in the North Sea. This includes detailed reservoir evaluation, methodology followed for sandface completion selection, steps taken to improve efficiency through lessons learned and continuously extend well lengths to be gravel packed in a low frac-window environment, and well performance results in this 24-well field development, with focus on the 7 out of 13 oil producers, detailing 3 of them.

Post-fracture proppant flowback has been an unwanted result of high-pressure/high-temperature hard-rock fracturing in the Mahakam river delta for a number of years, causing abundant production-related issues coupled with additional operational risks for the operator. Previous attempts to reduce proppant flowback with resin-coated proppant (RCP) have proven to be both unsuccessful and expensive due to the brittle nature of the hardened RCP and the extended cleanout periods associated with post-job fracture cleanout using RCP in the swamp environment, leading the operator to search for an alternative solution. In early 2012, the service company implemented a new proppant flowback control service for mid- to high-temperature wells. This service has been applied to the high-pressure/high-temperature fracturing campaign in the Mahakam delta with excellent results. The service consists of a resin-coated fiber additive coupled with technical support software for design and optimization purposes. The service was pioneered on four hydraulically fractured wells throughout 2012 and 2013. From the four wells currently treated with the new proppant flowback control service, a total of 180 lbm of proppant has been recorded at surface production facilities. All of this proppant is known to be from well A (approximately 0.18% of total proppant placed during fracture treatment). Wells B, C, and D have all recorded zero proppant returned to date. None of the four wells shows any indication of perforation burial from proppant, and there has been no decline in production that can be attributed to proppant flowback. Introduction Over the last 30 years, an operator has been developing several fields in the Mahakam river delta, in the province of East Kalimantan, Borneo, Indonesia (Fig. 1). The fields comprise a series of interbedded deltaic sandstones, shales, coals, and, locally, limestones, with gas-bearing sand bodies, typically with a total vertical depth of less than 12,000 ft. The majority of the wells are multizone gas producers completed with cemented tubing that are perforated and produced using a bottom-up strategy. Hydraulic fracturing operations are currently performed in two separate fields within the Mahakam delta. The fracture targets in both cases are medium- to low-permeability gas reservoirs in hard-rock formations. In this case, this is defined as reservoirs with ~1.0 mD permeability and lower and a Young's modulus of >4.0 Mpsi. The fracturing fluid utilized is a high-temperature organo-metallic crosslinked system with high-strength ceramic proppant that is used because of the reservoir and stress environment in the region. The operator has endured proppant flowback following hydraulic fracturing in both fields. In some cases, this proppant flowback caused considerable production loss with production meeting only 20% of the full potential of the well. This is due to restrictive well choking after proppant detection, as seen in the Fig. 2 for well Z. There have been cases of both perforation burial, leading to well shut-in for cleanout and proppant production at surface. The potential of further lost production and extensive damage to surface necessitated a permanent solution to proppant flowback in the Mahakam delta.

Current oil and gas volatile market environment and the increase focus towards sustainability, it is essential to develop more economically and ecofriendly technologies in oil and gas industry environment. Maintain well integrity is mandatory towards developing oilfields to contain the reservoir fluids within the wellbore, however it becomes more critical in developing new underground gas storage reservoir in Italy. During construction phase of gas production and storage wells, one goal, besides hydraulic isolation of the production casing with cement, is the sand production containment during production cycle of the field. Sand production, even in small quantities, will eventually erode downhole and surface equipment leading to potential catastrophic scenarios of uncontrol reservoir fluid reaching surface. These can have significant health, environmental, and economic impact. Additionally, the impending need for well intervention, along with high re-entry costs, will further weaken revenue margins. In high permeability reservoirs required for underground gas storage projects, the injection and production cycles can lead to stresses applied in nearby wellbore formation which will destabilize the sandstone grains leading to sand production. To mitigate the sand production into the wellbore, a gravel pack operation will support the wellbore, consolidating the space behind the production screens. In this field, a high-risk failure was identified for traditional alpha-beta gravel pack methodology. This could lead to expensive recovery operations for the client and service provider to restore the well and re-perform the gravel pack. To tap different part of the reservoir, one well in particular had to be sidetracked from 9-5/8in casing resulting in a long clay interval being exposed susceptible of instability. It was required to isolate this interval to avoid disturbing the clay interval during gravel pack operations, however, to accommodate the completion, the optimum solution was to use expandable liner. Using this zonal isolation technique to regain well integrity, along with redesign of gravel pack carrier fluid technology led to a successful job securing client position as a reliable field operator. The field operator was committed for high level of safety during operations, starting from design phase through the execution, to achieve long-term well integrity and performance.

No abstract

High Rate Water Pack (HRWP) treatments are used in cased hole gravel packs with the intention of creating small fractures to bypass near wellbore damage and improve perforation packing. Despite their popularity as a sand control technique, there has never been a software model developed specifically for HRWP treatments, and so their design has been largely driven by trial-and-error based on local field experience. Often, local field experience is insufficient to achieve the desired results due to uncertainties in the fracture initiation, propagation and packing mechanisms. The ability to model the initiation and packing of the fracture provides a better understanding of the achievable perforation packing in a specific well and how to maximize it. Such a model must simultaneously simulate fluid hydraulics, wellbore packing, fracture initiation and propagation, and gravel placement. Models exist for gravel packing that can predict packing in the wellbore annulus and perforations, but they do not account for initiation, propagation and packing of the fractures. Multiple models are also available specifically for fracturing design, but most of these do not account for wellbore packing. These models are more suited for conventional hydraulic fracturing and frac pack treatments using highly viscous or crosslinked fluids. Such fracturing models tend to overpredict fluid leak-off in soft rock formations, especially with low viscosity fluids, and consequently predict premature screen-outs under conditions in which HRWP treatments are in practice successfully placed. This paper introduces the first software model that combines both wellbore and perforation packing, along with the initiation and packing of small fractures, to facilitate successful HRWP treatments. Examples of how the model can be used to optimize HRWP treatments are discussed and the various parameters that impact HRWP design are also assessed. Several case studies are presented comparing modelled and actual data to both validate the model and demonstrate how it can be used to optimize the designs for offset wells.