Managing severe-to-total lost circulation can be especially challenging in naturally fractured formations. This situation becomes further complicated if it is a producing formation. Particulate lost circulation materials (LCM) have been used to manage lost circulation for many years. However, current LCMs are not efficient in terms of size and application methods to cure severe-to-total losses, such as highly fractured reservoirs.In the present paper, a novel acid-soluble combination in the form of an engineered composite LCM solution (ECS) with a multi-modal particle size distribution (PSD) has the potential to manage severeto-total loss circulation situations in naturally fractured reservoir formations. The multi-modal PSD and unique combination of particles will help manage any uncertainties in fracture sizes, and the larger particles present will aid in plugging large fractures. The results of a laboratory investigation will be presented, highlighting the potential benefits of this solution.When managing severe-to-total losses in highly fractured reservoir formations, particulates alone may not be effective, thus the LCM should preferably be acid soluble. The combination of a large multi-modal PSD LCM containing a fibrous material along with platelet particles was designed as a candidate for dealing with these extreme losses. The solution developed is capable of plugging laboratory-simulated fracture sizes in the range of 5,000 m. It was further demonstrated that supplementing with another larger LCM platelet materials enhanced its capability to seal 0.5 in. (12.5 mm) in the lab. A significant determination in the solution developed is up to 96% soluble in 15% HCl and organic acids. This paper will discuss in detail the product concentration, testing methodology, and results. In addition, the strategy to apply these materials in the field will be discussed.The large PSD, acid-soluble LCM solution can help manage uncertainties in fracture sizes and allow for curing severe-to-total losses in naturally fractured reservoir formations.

Disposal of drill cuttings from non-aqueous drilling fluids (NAF) can be a significant expense and logistical issue for the operator of a drilling rig. NAFs typically contain high levels of salts, commonly calcium chloride or sodium chloride, in the internal phase of the emulsion. These salts are highly beneficial for wellbore-stabilization performance, but pose issues for the disposal of drill cuttings because the salts do not biodegrade and can accumulate in high concentrations in soil. A salt-free NAF has been developed and field validated in the Western Canadian Sedimentary Basin in Alberta, Canada. The system uses a biodegradable organic to provide an internal phase with equivalent water activity to traditional salt-containing systems. This results in a fluid system with the performance and benefits of a conventional NAF, while potentially allowing for greater cuttings disposal options. Depending on local regulations, the system has the potential to reduce environmental and long-term liability concerns by being able to land-farm drilled cuttings without hindering plant growth. Three wells on a seven-well pad were drilled with the salt-free NAF; the other four were drilled with a conventional invert emulsion fluid (IEF). Cuttings from one of each type of well were collected. A bioremediation study was conducted to analyze the cuttings for electrical conductivity and plant growth. Cuttings were delivered to the lab for testing and analysis. Laboratory testing showed that when mixed with top soil, the salt-free cuttings allowed for viable plant growth; whereas, the conventional cuttings did not allow for plant growth. This paper will discuss in detail the bioremediation study of the salt-free NAF. A salt-free NAF has been developed in the lab and successfully validated in the field. Cuttings from the salt-free system showed superior plant growth when compared to conventional, salt-containing systems. This system is expected to offer expanded options for cuttings disposal and, ultimately, reduce the cost and liability associated with using NAFs in many areas.

Lost circulation is an extremely difficult challenge to overcome in areas with large natural fractures. Few lost circulation materials (LCMs) are capableoftreatingsuch zones where severe to total losses occur, particularlyin the reservoir sections. Particulate-based LCMs are commonly used to help mitigate losses but mightnot contain the proper particle size distribution (PSD) or acid-solubility characteristicsfor useful application in production zones. This paper discusses a novel particulate-based LCMthat is an engineered composite solution (ECS) with a multimodal PSD comprised of acid-soluble components. The multimodal PSD provides the necessary particle sizes to seal a range of fracture widths, including large fractures where total losses canoccur. The acid solubility of the LCM can enable proper removal to help prevent hindering well production. Laboratory results are explained todemonstrate the potential effectiveness of the LCM forsealing large natural fractures. Acid solubility in a reservoir or production zone is important. LCMs used in these zones have tobe removed to permit maximum formation production. For large natural fractures, large particulates are necessaryto effectively mitigate losses. TheECS was designed to include particulates and fibers of various sizes and shapes to plug large-width fractures while retaining the ability to plug smaller- to intermediate-width fractures. This blend can plug laboratory simulated fractures up to 5,000micronsin width.When supplemented with an additional chip particulate, it can plug fractures up to 7,000 microns. The acid-soluble component of this blend is degradable in both 10% hydrochloric (HCl) and 10% formic acids. This paperdiscusses product specifications, such as PSD, recommended treatments, and laboratory performance test results, including acidizing treatment of anLCM plug contaminated with invert emulsion fluid.

LE1 7RHRate constants are reported for the reaction between bromide ions and the complex ion [PdCl(tedien)]+ (tedien = NNN"N"-tetraethyldiethylenetriamine) in aqueous solution containing various concentrations of bromide salts. The first-order rate constant for the unimolecular substitution reaction decreases with increase in salt concentration, the effect being more marked through the series NBun4+ > NPr,+ > NEt,+ > NMe,+ > K+ N Na+. Comparison of rate data and solubilities of the complex chloride salt in 1 .O mol dm-3 KCI, [NEt,]CI, and [NBu4]CI indicates that the dominant salt effect operates on the transition state, where hydration and ion-size effects lead to a marked destabilisation.

Every field development requirement is to keep the capital and operational expenditures (CAPEX and OPEX) within reasonable limits, at the same time exploring matured or new technology that can achieve cost limit objectives. With the uncertainties, cyclic nature and instability in the oil and gas global investment and the fluctuation in crude oil pricing, operators of the exploration and production (E&P) energy industries and service providers are constantly looking for better and more efficient cost saving products and services. The challenge of maximizing hydrocarbon recovery in deep water completion with minimum investment, while maintaining the highest level of Health Safety and Environment (HSE) and service delivery always leads to new products and service delivery techniques. In the operator's Bonga subsea field, the conventional completions technique for all open hole Standalone Screen (SAS) completion installations are performed in multiple trips. The first trip involved running a gravel pack packer with screen assembly which allows a gravel pack packer service tool and an internal string with a pump thru wash-down capability enable ease of deployment, toe-heel circulation, packer setting and testing. The internal string which comprises of the packer setting tool, internal wash pipe and accessories is recovered after completion of the first trip into the open hole formation section. The second trip involved running the production tubing, production packer, downhole gauge mandrel, safety valve and other completions accessories and landing the production string on the tubing hanger. The major objectives and drivers of the open hole Single Trip Stand-Alone Screen completion (STC-SAS) in deep offshore environment is basically to save rig costs, use proven and emerging technologies, employ completions best practices, reduce exposure of personnel to safety hazards and of course reduce Non-Productive Times (NPT). New completions technique with different services and product providers could pose a challenge in terms of vendor interface management, equipment compatibility and procedural integration of multiple downhole equipment with different operating boundaries and limits. The single trip stand-alone screen completions concept in deep water was generated by the operator's Wells Front End Completion and Well Intervention team in December 2015. This was driven by an opportunity to further reduce well delivery rig time which is a premium in deep water subsea completions. The average completions time in the field stood at 10 days per 10,000ft well. The group was challenged to further improve the well delivery time. However, there was no bench mark as the industry data showed that a single trip open hole stand-alone screen completion had not been installed globally in deep water subsea environment. This paper presents the evolution of the completions design, the critical challenges in the contractor management, downhole equipment interfaces, operational steps, risks and the lessons learned during the job execution that led to the successful installation of the first single trip open hole sandface STC SAS in deep water environment.