Background: We determine whether Diabetes Connect (DC), a Web-based diabetes self-management program, can help patients effectively manage their diabetes and improve clinical outcomes. Methods: Diabetes Connect is a 12-month program that allows patients with type 2 diabetes mellitus to upload their blood glucose readings to a database, monitor trends, and share their data with their providers. To examine the impact of the program, we analyzed patient utilization and engagement data, clinical outcomes, as well as qualitative feedback from current and potential users through focus groups. Results: We analyzed 75 out of 166 patients. Mean age was 61 years (range 27-87). Patients engaged in DC had an average hemoglobin A1c (HbA1c) change of 1.5%, while nonengaged patients had a HbA1c change of 0.4% (p = .05). Patients with the best outcomes (HbAlc decline of at least 0.8%) typically took less than 10 days to upload, while patients with the worst outcomes (a rise in HbAlc) took an average of 65 days to upload. Patients with more engaged providers had a better HbA1c change (1.39% versus 0.87%) for practices with an average of 74 versus 30 logins/providers. Conclusions: Patient engagement in the program has a positive impact on the outcomes of this collaborative Web-based diabetes self-management tool. Patients who engage early and remain active have better clinical outcomes than unengaged patients. Provider engagement, too, was found critical in engaging patients in DC.

The role of the β2AR (β2 adrenergic receptor) after stroke is unclear as pharmacological manipulations of the β2AR have produced contradictory results. We previously showed that mice deficient in the β2AR (β2KO) had smaller infarcts compared with WT (wild-type) mice (FVB) after MCAO (middle cerebral artery occlusion), a model of stroke. To elucidate mechanisms of this neuroprotection, we evaluated changes in gene expression using microarrays comparing differences before and after MCAO, and differences between genotypes. Genes associated with inflammation and cell deaths were enriched after MCAO in both genotypes, and we identified several genes not previously shown to increase following ischaemia (Ccl9, Gem and Prg4). In addition to networks that were similar between genotypes, one network with a central core of GPCR (G-protein-coupled receptor) and including biological functions such as carbohydrate metabolism, small molecule biochemistry and inflammation was identified in FVB mice but not in β2KO mice. Analysis of differences between genotypes revealed 11 genes differentially expressed by genotype both before and after ischaemia. We demonstrate greater Glo1 protein levels and lower Pmaip/Noxa mRNA levels in β2KO mice in both sham and MCAO conditions. As both genes are implicated in NF-κB (nuclear factor κB) signalling, we measured p65 activity and TNFα (tumour necrosis factor α) levels 24 h after MCAO. MCAO-induced p65 activation and post-ischaemic TNFα production were both greater in FVB compared with β2KO mice. These results suggest that loss of β2AR signalling results in a neuroprotective phenotype in part due to decreased NF-κB signalling, decreased inflammation and decreased apoptotic signalling in the brain.

The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.

Cement Packer is a cost-effective alternative to workover for monetizing hydrocarbon reservoirs above the well top packer. While conventional cement packer utilizes coil tubing for cement placement, an innovative and more cost-effective approach was successfully implemented with only slickline and pumping unit, without utilizing coil tubing. This reduced the overall cost of the well intervention by 60%, significantly reduced operational safety risks and is exceptionally suitable in the current challenging environment. Similar to conventional cement packer, the operation begins with setting a plug inside the tubing below the targeted perforation depth and punching the tubing to create tubing-casing communication. The tubing was then flushed with surfactant and weak acid to remove any potential contaminants. The cement was then bullheaded from the surface through the tubing and into the casing while being chased by two foam wiper balls. The foam wiper balls were subsequently pushed with inhibited sea water mixed with cement retarder to prevent any leftover cement from hardening in the tubing. The hardened cement column in the production casing then acts as a barrier to satisfy operating guideline for two pressure barriers in a well. Two cement packer jobs were performed during this campaign; one via conventional method with coil tubing unit (CTU) and a fit-for-purpose version without the CTU. Pressure test from the tubing and casing after the cement hardened indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool demonstrated thick column of good cement thus confirming the cement integrity of the non-CTU method. It was able to achieve similar pressure isolation as the conventional CTU method at 60% lower cost which allowed for significant cost saving. It also reduced the operation time by 50% since the cement was pumped at a higher rate through the well tubing. The turbulent flow regime via high rate pumping also resulted in thicker column of good cement (200m vs 120m) compared to conventional method. The only drawback encountered was the unexpected obstruction caused by leftover cement behind the foam ball. However, this can be removed through milling or fine-tuning the retarded sea water recipe. Post perforation, there was a sharp increase in the tubing pressure while the casing pressure remained low, further confirming the success of this method. This innovative method will be the standard method for any future cement packer operations while the conventional method with coil tubing will only be applied in complex situations. This new Cement Packer technique has introduced substantial cost saving compared to the conventional cement packer method. It will enable monetization of more minor reservoirs. The method is exceptionally relevant to a mature field especially in the current challenging business environment.

The Cement Packer approach has been successfully implemented in ExxonMobil Exploration & Production Malaysia Inc. (EMEPMI) to further develop minor gas reservoirs. The reservoir of interest is of relatively poor quality and has not been tested, thus making conventional development potentially not cost effective. Several viable approaches were identified and assessed to appraise and develop the reservoir. The cement packer method, which requires relatively minimal investment was then selected as being the most suitable in pursuing these behind casing opportunities. Group 1 sands in Field A are the shallowest hydrocarbon reservoirs which are relatively thin and have low porosity and permeability. The existing completions are currently producing from deeper reservoirs, with the top packer located below the Group 1 sands. Developing the opportunities behind casing in these sands using the conventional pull tubing workover approach may be cost prohibitive. The cement packer approach, where the tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing, was identified as one of the potential cost effective solution. The hardened cement then acts as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized. Prior to well entry, tubing and casing integrity tests were performed to confirm the integrity. This step is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement is hardened, pressure test from the tubing and from the casing indicated the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool also displayed nearly 120m of fair to good cement above the target perforation depth. These data served as basis and proof that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the relatively poor reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to increase the probability of maximum reservoir contact while minimizing skin. Post perforation, a sharp increase in the tubing pressure was observed, indicating pressure influx from the reservoir. The casing pressure however, remained low, confirming no tubing-casing communication and thus the success of the cement packer. The well was later able to unload naturally from the high reservoir pressure. The work program also managed to confirm the producibility of the reservoirs. This successful approach has opened up potential application to similar stranded reservoirs behind casing.