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This paper provides new physical insight into the coupling between flow dynamics and cavitation bubble cloud behaviour at conditions relevant to both cavitation inception and the more complex phenomenon of flow “choking” using a multiphase compressible framework. Understanding the cavitation bubble cloud process and the parameters that determine its break-off frequency is important for control of phenomena such as structure vibration and erosion. Initially, the role of the pressure waves in the flow development is investigated. We highlight the differences between “physical” and “artificial” numerical waves by comparing cases with different boundary and differencing schemes. We analyse in detail the prediction of the coupling of flow and cavitation dynamics in a micro-channel 20 μm high containing Diesel at pressure differences 7 MPa and 8.5 MPa, corresponding to cavitation inception and "choking" conditions respectively. The results have a very good agreement with experimental data and demonstrate that pressure wave dynamics, rather than the “re-entrant jet dynamics” suggested by previous studies, determine the characteristics of the bubble cloud dynamics under “choking” conditions.

Summary Water production in northeast Syria has increased significantly in recent years. As a result, costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity. Production logging tool (PLT) surveys, combined with a reservoir study, showed that good-quality sands were not properly swept by the water, probably because of poor connectivity in the reservoir. It was anticipated that these unswept sands could contribute to production if the watered-out sands were shut off. A newly developed gel/cement has been used to shut off the watered-out sands in a cost-effective manner. The gel/cement system combines the properties of two shutoff techniques: Cement for mechanically strong perforation shutoff. Gel for excellent matrix shutoff. The gel, used as "mix water" of the cement, will be squeezed into the matrix, creating a shallow matrix shutoff. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shutoff performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will re-establish the oil production. The shutoff zones can be reopened later in the well's life when artificial lift has been installed. The system was tested in the field in two wells. In the first field trial, 84 m of perforations (gross) was squeezed off with the gel/cement in a single attempt. After reperforation of the top and the middle zone, the well produced at a strongly reduced water cut (i.e., 25 to 33% compared with 60 to 62% before the treatment) and an increased oil production (i.e., 3,000 BOPD compared with 1,000 BOPD before the treatment). The oil production declined to 2,000 BOPD over a year; the water cut gradually increased over that period to 56%. In the second well, full shutoff was achieved but oil production could not be resumed for reasons that are not fully understood.

Lifetime DMFC performance degradation studies were performed using both single cell and high throughput catalyst screening techniques. Efforts to mitigate the degradation of the DMFC were focused on acid pre-treatment of the anode catalyst, identification of novel anode catalyst materials, load cycling techniques, and improvement of the catalyst layer deposition. Acid pre-treatment of the anode catalyst yielded no significant decrease in the time dependent performance degradation. No performance improvement was identified using the novel catalysts developed or with the load cycling methods. The employment of a membrane catalyst deposition technique demonstrated superior performance over direct gas diffusion layer catalyst deposition.

This paper describes the results obtained, the techniques used, and the challenges involved in providing a water shutoff solution to a subsea gas production well with a sand screen completion on the Rose field in the UK Southern North Sea. The project began with a detailed reservoir analysis to determine if intervention was practical in this subhydrostatic well. This led to the planning and sourcing of suitable coiled tubing (CT) and pumping equipment, as well as an associated zonal isolation chemical solution. The design of the intervention was tailored to operate within the environment of a jackup installation located over a subsea well. This included CT and fluid pumping operations. The basis of the technique was to shut off the water-producing interval in the horizontal completion and isolate the unsupported annulus between the water bearing and gas producing intervals. The greatest challenge was to isolate the horizontal annulus between the gas and water producing zones. This required setting of mechanical barriers and the placement of suitable zonal isolation material that would set quickly without slumping and leaving the top of the annulus unsealed. This paper details the lessons learned throughout the intervention. In the case of the Rose well, it now produces dry gas. This was the first time globally that this technique had been applied to a subsea horizontal well.

Water production in the North-east of Syria has increased significantly in recent years. As a result costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity. PLT surveys combined with a reservoir study showed that good-quality sands were not properly swept by the water, probably due to poor connectivity in the reservoir. It was anticipated that these un-swept sands could contribute to production if the watered out sands were shut-off. A newly developed gel-cement has been used to shut-off the watered out sands in a cost-effective manner. The gel-cement system combines the properties of two shut-off techniques: ■Cement for mechanically strong perforation shut off.■Gel for excellent matrix shut off. The gel, used as ‘mix water’ of the cement, will be squeezed into the matrix creating a shallow matrix shut off. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shut off performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will reestablish the oil production. The shut off zones can be reopened later in the well's life when artificial lift has been installed. In the first field trial 84 meters of perforations (gross) were squeezed of with the gel-cement in a single attempt. After re-perforation of the top and the middle zone the well produced at a strongly reduced water cut, i.e. 25–33% compared to 60–62% before the treatment, and an increased oil production, i.e. 3000 bopd compared to 1000 bopd before the treatment. The oil production declined to 2000 bopd over a year. The water cut gradually increased over that period to 56%.

Abstract A coiled tubing stimulation treatment featuring a new high flash-point solvent was performed on an offshore injection well in the Ninian Field. This stimulation treatment was performed to–remove hydrocarbon residue and deep clay damage–stimulate low-permeability zones–increase water injection rates in an offshore well The target zone was treated with 587 bbl of sequential HF acid to prevent swelling of near- wellbore fines, solids, and clay. The application of sequential HF acid increased permeability 10-fold over standard HF acid treatments. An inflatable packer was placed between the upper zones and suspected weak tubing, confining the treatment to the target zones. The treatment successfully reduced the formation skin factor, which increased the injection rate by 100% (0.25 bbl/min to 0.5 bbl/ min) and reduced the surface pressure by 3%. Introduction The Ninian Field lies in blocks 3/3 and 3/8 approximately 100 miles east of the Shetland Islands. The field was discovered in January 1974, and the first oil from the field was produced in December 1978. It is a Brent sequence reservoir with recoverable reserves of around 1.2 billion barrels. Current average daily production from the field is approximately 60,000 BOPD. Water injection well C08 is located in the central area of the main field (Fig. 1). The well was recompleted in August 1992 for the purpose of injection into the low-permeability sands within the reservoir to support low water-cut production from two nearby producers. The low-permeability sands targeted for injection support were Zones Al/A2 (Broom) and El (Lower Ness). After the recompletion, the well was configured to inject into the bottom sands in the reservoir (Zone Al/A2), and a maximum injection rate of 0.25 bbl/min at 3,700 psi was obtained. This rate was not great enough to help support simultaneous production from the nearby producers. Core analysis of this zone indicated a high clay content. Clay swelling, fines migration, and well debris, including rust and scale, were contributing to the low injection rate. A subsequent attempt to manipulate the selective completion was unsuccessful. A hydrocarbon-based, xylene-soluble deposit was present from 14,900 ft, which prevented wireline tools from accessing the selective completion. The well also developed an intermittent tubing leak, which caused occasional pressure buildup on the annulus. Based on well conditions, a coiled tubing stimulation treatment was proposed to address the problems in the well. The proposed treatment had two objectives:–to circulate a suitable solvent to remove the hydrocarbon deposit and allow the wireline tools to manipulate the completion–to perform a sequential HF acid treatment to stimulate low-permeability Zone A1/A2 to increase water injection to support low water-cut production at nearby producers During this treatment, the tubing would be protected by an inflatable packer set above the treatment zone, which isolated the tubing above the packer and allowed selective injection into the target zone. Treatment Plan Solvent Selection. Various solvents were tested on samples of the hydrocarbon residue recovered from the well. Although the residue was soluble in xylene, a new xylene substitute was chosen. In addition to providing an alternative to hazardous benzene, ethylbenzene, toluene, and xylene solvents, this xylene substitute has a flash point of l.50 F, which makes it ideal for offshore use. P. 569

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