Simple procedures using charts for predicting frictioniprcssure gradients during turbulent-turbulent flow in pipes and the pressure changes over bends, changes of section, and valves are presented. For friction/pressure gradients comparison is made with the procedures of Baroczy, Lockhart and Martinelli, Martinelli and Nelson, Collier, Becker et aZ., and Thorn.

Within the Middle East region the development of large gas accumulation has resulted in a need for hydrate control within the produced fluids during the winter months. Development of kinetic hydrate inhibitors (KHI) as an alternative to thermodynamic hydrate inhibitors (THI) such as methanol or mono ethylene glycol (MEG) has resulted in a significant reduction in process equipment size and associated operational costs but the disposal of the resulting KHI that predominately partions into the produced water and corrosion inhibitor constantly added to production lines has raised concerns about formation damage within the injection/disposal wells under matrix flow conditions This paper will present details from a set of corefloods which look at produced water re injection (PWRI) under matrix flow conditions within carbonate cores and the observed damage such KHI and KHI/CI solutions can produce within Arab D formation rock. The coreflood tests generated pressure profiles, cation, pH and KHI concentration within the coreflood effluent during the injection of these fluids to fully understand the process occurring within the rock (dissolution, ion exchange, precipitation/adsorption, filtration). The study then looked at mitigation methods for the damage that could be potentially induced and then based on understanding the two generations of KHI and associated corrosion inhibitor molecule structure what changes could be made to the produced fluid composition to eliminate the damage from forming in the first place. The paper outlines the mechanism of damage and mitigation to a flow assurance challenge that is receiving a significant amount of focus within the Middle East region at this time.

The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period of time different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention adsorption/ desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor as calcium salt onto the mineral surface of the reservoir.This study has been conducted to understand if the retention of phosphonate and phosphate ester inhibitors can be improved by adsorption of a charged polymer onto the rock prior to application of the scale inhibitor or if application of the same polymer enhancer after adsorption of the scale inhibitor will extend squeeze life. These tests have been carried out using pack floods at 85°C with synthetic North Sea produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer. This study shows how the different functional groups within the scale inhibitors interact with the mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations.

Control of inorganic scale within oilfield production wells via the scale squeeze process is well documented. The life time of the squeeze treatment is dictated by the cumulative volume of produced water flowing through the treated interval until the minimum inhibitor concentration (MIC) of the scale inhibitor is reached. Inhibitor chemicals with strong retention and low MIC values have been developed, deployed and for many years phosphonates and polymers containing phosphonate functional groups have been widely used.This study looks at the issues faced by an operator with a low temperature sandstone reservoir of only 40°C and the challenges this low temperature brought which include high MIC for sulphate scale control and poor chemical retention & release observed during the reservoir condition corefloods. These findings will be compared and contrasted with two other higher temperature (71°C and 95°C) sandstone reservoirs where phosphonates and phosphate ester chemicals have been evaluated and deployed in the field.The findings from this detailed coreflood study and review of previous experimental/field deployed scale squeeze treatment data shows that phosphonates work very well at elevated temperatures at and above 70°C where their stronger retention and excellent release profiles makes them a favoured chemical for such treatments, however at lower temperatures these molecules are not well retained on the rock and it is the phosphate ester chemicals that are more effective and provided the longer squeeze life. Comments on the interaction/performance of polymer scale inhibitors will also be made for these low temperature conditionsThe implication of these findings clearly show that phosphate esters offer the potential for extended squeeze lifetime in the Ͻ50°C sandstone reservoirs which are being developed in Northern Norway (Barents Sea) and the shallow depth, cool reservoirs being developed in offshore Brazil.

Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV's), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale. One of the industry standard test methods used to screen inhibitors for barium sulphate inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of barium sulphate scale at two different temperatures and therefore different supersaturations for a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation). The findings from this study have significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable chemicals that perform better under higher shear conditions.