In subsea oil and gas production, a transition away from complete gas hydrate avoidance to riskbased hydrate management has the potential to offer cost savings and improved viability for new developments. Rigorous characterization of hydrate formation probability (via the measurement of statistically significant numbers of independent hydrate formation events) represents a critical step towards accurate quantification of hydrate blockage risk. Such characterization is especially pertinent when deploying low dosage kinetic hydrate inhibitors (KHIs) which, unlike thermodynamic hydrate inhibitors (THIs), affect hydrate formation kinetics rather than thermodynamic stability envelopes. Here we demonstrate the use of a 2nd generation, Peltiercooled, high pressure, stirred, automated lag time apparatus (HPS-ALTA) to efficiently measure hydrate formation under conditions simulating a methane dominant natural gas asset. Over 2,500 hydrate formation events were measured using a low salt content brine, enabling the production of smooth, high resolution hydrate probability distributions in the presence of three inhibitor chemical additives and combinations thereof (a corrosion inhibitor, a KHI and a conventional THI). Beyond enabling rapid, high fidelity testing of potential inhibitor interactions, the results explicitly demonstrate the ability to effectively manipulate formation probability boundaries via a 2 combination of thermodynamic and kinetic inhibition effects. Such hybrid inhibition strategies can be used to achieve long induction times at operationally relevant formation temperatures (over 2 days at 2.5 °C in this study) and may be more beneficial and/or cost-effective than strategies focused on complete hydrate avoidance.

This paper reports a case study on the selection of a HP/HT/HS scale inhibitor for CaCO 3 precipitation in the ultrahigh temperature and pressure environment experienced in the TotalFinaElf Elgin-Franklin assets. The paper will outline the scale management, inhibitor selection and deployment strategies adopted for scale control in this extremely harsh environment. The downhole temperature in these wells can be up to 200ºC and pressures can exceed 16000 psi. Problems are further enhanced by large decreases in pressure over relatively short changes in well depth. The literature is scant on studies performed at these conditions and a thorough screening of a wide range of scale inhibitor products and deployment techniques is an essential asset to the continued exploitation of very harsh well conditions.A new, upgraded scale prediction routine has shown that CaCO 3 precipitation will occur over the whole range of reservoir conditions. A wide range of scale inhibitor chemistries including sulphonated polymers, phosphonates and some novel development products have been screened using four industry standard techniques. Thermal ageing revealed any instability caused by thermal degredation of the inhibitor molecule and jar test compatibility experiments performed at field temperature showed chemical incompatibilities with field brines. Dynamic scaling loop experiments were performed on not only the fresh inhibitor chemistries but also on thermally aged samples. The thermally aged samples were also analysed spectroscopically to identify any breakdown products and mechanisms. Finally coreflood experimentation was used to highlight inhibitor return profiles over a simulated squeeze treatment and to look for any formation damage that may have occurred.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAqueous based scale inhibitor squeeze treatments have been routinely deployed on Total Oil Marine's North Alwyn field for many years. More recently, declining reservoir pressure in parts of the field, coupled to poor reservoir communication has led to a considerable increase in the time required to bring treated wells back onto production. On subsea well 3/4a-15s, it was anticipated that extended shut-in periods would be required to allow sufficient pressure build up for production restart following a platform squeeze.To minimise deferred oil cost associated with scale inhibitor treatments an alternative deployment technique has been applied to treat subsea wells such as 3/4a-15s on North Alwyn.A weighted solid scale inhibitor capsule, suspended in a carrier brine has been pumped to the wellhead and allowed to fall, under gravity into the sump. On reaching the sump, the diffusion of scale inhibitor from the capsule established a concentration gradient, which delivered a near constant level of inhibitor over the lifetime of the treatment.The subsea well on North Alwyn treated using this technique returned to production in less than 24 hours. In addition, the encapsulated inhibitor treatments have out-performed previous squeeze treatments, protecting a large volume of water to the minimum inhibitor concentration (MIC). This paper will describe the concept of the delivery system, details of the treatments and present the return profiles.

During the production of offshore oil and gas, production fluids will cool toward seafloor temperatures which will place the flowline into the natural gas hydrate stability region. Small particles of hydrate can form, which can aggregate and result in blockage of the flowline. The most common hydrate management strategy involves using large volumes of thermodynamic inhibitor (THI) to operate outside the hydrate stability region. The THI hydrate management strategy represents a significant CAPEX and OPEX investment, rendering some deepwater fields economically unviable to develop. Low dosage hydrate inhibitors (LDHIs), in the form of kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs), present an alternative to THIs. AAs allow hydrates to form, but limit hydrate agglomeration and enable the transport of a stable hydrate-in-oil slurry. AAs have traditionally been qualified for field deployment on black oils using high-pressure rocking cells and autoclaves. These tools provide qualitative assessments of AA performance, but are unable to resolve structure-function relationships at the interfacial length scale. In this study, a quantitative micromechanical force (MMF) has been deployed to study the performance of seven industry AAs. Four of these AAs are current generation AAs being deployed today and the remainder represent successive generations of AA products. The results illustrate that an effective AA must be one that lowers the cohesive forces between hydrate particles. For the four generations of AA chemistry an improvement in the maximum hydrate cohesive force reduction for the current generation chemistry (80%> force reduction) relative to the previous ones (40-50% force reduction) we observed. All current generation AA chemistries lower hydrate cohesive force by more than >80% indicating a high likelihood of successfully dispersing hydrates. To assess this likelihood each chemistry was then validated in high pressure sapphire autoclave under high shear; in this technique, which is analogous to more traditional qualification methods, performance may be quantified in terms of the maximum relative torque, defined as the ratio of the maximum torque required to maintain a set shear rate in the presence of hydrates to the torque required before hydrate formation. Consistent with the observations in the MMF, all current generation AAs kept the relative torque < 2, while systems with no AA experienced a maximum relative torque of ~20. The MMF results are consistent with the more traditional autoclave qualification but provides a more quantitative insight into hydrate cohesion which is a key aspect of AA performance.