A growing number
of G-protein-coupled receptor (GPCR)
structures
reveal novel transmembrane lipid-exposed allosteric sites. Ligands
must first partition into the surrounding membrane and take lipid
paths to these sites. Remarkably, a significant part of the bound
ligands appears exposed to the membrane lipids. The experimental structures
do not usually account for the surrounding lipids, and their apparent
contribution to ligand access and binding is often overlooked and
poorly understood. Using classical and enhanced molecular dynamics
simulations, we show that membrane lipids are critical in the access
and binding of ORG27569 and its analogs at the transmembrane site
of cannabinoid CB1 receptor. The observed differences in the binding
affinity and cooperativity arise from the functional groups that interact
primarily with lipids. Our results demonstrate the significance of
incorporating membrane lipids as an integral component of transmembrane
sites for accurate characterization, binding-affinity calculations,
and lead optimization in drug discovery.
Maximum efficiency rate (MER) is the production rate above which the reservoir recovery (particularly around the well) is endangered thereby eroding lifecycle economic value. The current practice in the Niger Delta entails the application of the equilibrium concept which (in this case) requires the use of a combined graph of tubing head pressure (THP) and choke size against the production rate where the point of intersection between the plots is considered the stable equilibrium and the corresponding rate, the MER. However, experience has overtime shown that adjustment of the scale of the vertical axis would yield different values of MER; and thus can be adjudged as physically inconsistent.
To address this inconsistency, a robust methodology that will be acceptable to both the regulators and partners is being proposed by first understanding and establishing the limitation of the current methodology and demonstrating same using the combined THP and choke size versus production rate plots on a single graph. Subsequently, the relationship between key elements of changing THP (due to varying choke sizes) and their attendant back-pressure effect at the sand face impacting on reservoir withdrawal at given physical well conditions was established and normalized (using first order derivative function) to capture possible variations in the tubing head and sandface pressures over any production period.
The impact of choke size adjustment on the ‘changes’ in THP and production rate at a particular physical well condition was modeled and a combined plot of the ‘change’ in THP and production rate at varying choke sizes was then generated on a single graph. The result proves to be more physically consistent and can easily be replicated across the industry.
This paper demonstrates the gap in current MER estimation methodology and proposes a new thinking and more effective approach; sharing the results of its application and value for both regulators and operators.
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