Perforation design including gun size, type, charge weight, configuration (shot density, entrance hole, phasing) and deployment options can significantly impact well productivity post perforation. Gun selection is a key process to ensure that the optimum gun that can yield maximum well productivity and minimum skin due to perforation has been considered. Gun performance modelling and sensitivity analysis should be conducted to compare the performance of various guns and to select the optimum gun suitable for well and reservoir conditions. Gun performance under downhole condition is a complex process and uncertainty analysis should be considered when converting API gun test data into downhole condition. It is always preferred to use stressed-core test data such as API section II/IV. However, data analysis and alteration might still be required to replicate the exact downhole condition. This paper presents a successful case history of perforating 130 m in a single coiled tubing conveyed run using Live Well Deployment system in 6,000-m deep gas and condensate reservoir with an average permeability of 10 mD and reservoir pressure of 12,500 psi. Production has increased by 20% compared to reference wells due to the intensive perforation testing and design process conducted to this well prior to operation. Extensive modelling work has been conducted to evaluate the performance of deep penetrating guns compared to conventional guns, in addition to uncertainty analysis and risk assessment regarding the impact of using API section-I compared to Section-II/IV data. The paper demonstrates a robust workflow for gun selection and gun performance evaluation process, which can be used as guideline to perforation design process.

The Underground Gas Storage (UGS) working gas capacity is one of the important design parameters for a UGS project. The objective of this paper is to demonstrate a case study from Sichuan area, China, where a fractured carbonate gas reservoir was used for UGS and show the key factors that should be considered to optimize UGS working gas capacity and help to secure energy supply during peak season. The dynamic simulation model was history matched on both depletion and storage. This model was coupled with 4D Geomechanics effects. It was then employed to capture the key parameters that will affect the working gas capacity. Based on the 4D Geomechanical integrity and facility assessment results, the forecast model was created using the subsurface and surface facility constraints. The study workflow included setting up the forecast model, uncertainty analysis and sensitivity analysis to capture the key driving parameters for the working gas volume. This study also included sensitivities of emergency gas supply during peak winter season. This study showed that the main factors that determine the UGS working gas capacity are the initial gas in place, tubing head pressure (THP) during withdrawal phase, bottom hole pressure (BHP) during injection phase, well pattern and well count. It was observed that each injection/production cycle is affected by the previous cycles. The simulation showed that the incremental working gas volume represented as a trend can be better fitted by a power function with both THP and BHP. It also demonstrated that lowering the THP limitation is more effective than increasing the BHP limitation. However, this may require surface facility upgrading. The optimum operating condition was identified by considering all engineering and geomechanical constrains such as erosion, wellbore integrity and cap rock integrity. This is used to guide the UGS daily operations with optimum production/injection rate of each well in a safe manner. The study recommended to implement a stepwise strategy to reach the working gas capacity. This paper presents a novel practical workflow and methodology to implement increased UGS reservoir working capacity. It also provides a practical way to forecast the operational pressure range and quickly predict the deliverability of emergency gas supply under various market demands.

A large amount of gas is trapped in the transition zones in tight, conventional reservoirs. These reservoirs tend to be prone to water production because the in-situ water saturation is at or exceeds the critical water saturation. The water-production issue is even more pronounced when wells are stimulated by hydraulic fracturing; the resultant water production might be interpreted to have its source in the aquifer below the free water level to a bad cement job or a connection to unknown faulting.As an example, a typical Rotliegendes Sandstone well was considered. It was completed and subsequently fractured, and produces gas with a high water-gas ratio. The objective of this study was to demonstrate how to ascertain the most likely source of the water; whether it was produced from the aquifer or from high water saturation matrix regions in the reservoir.Available fracture placement data were used to match analytically the pressures to confirm the stresses with the resultant fracture model compared with the one used for initial design. A box model was constructed in a reservoir simulator and the fracture was described using a Tartan grid. Using the analytical result as a base case the reservoir and fracture properties were adjusted using assisted history matching to replicate observed gas and water rates and flowing bottomhole pressure. The main matching variables were permeability, permeability anisotropy, stand-off to gas-water contact, relative permeability, gas and water end points saturations and fracture dimensions. The water saturation was derived from a saturation vs. height function; the power law factors in this equation can also be matched.Analysis of the fracture delivery indicated that the dimensions of the fracture could be different from the dimensions derived from the design. The fracture height and half-length in the post-fracture model showed a higher fracture height and a smaller half-length connecting potentially with free water. The assisted history matching demonstrated that the water rate behavior could best be explained as a result of high water saturation in the reservoir, rather than direct connection to the aquifer through an inadequate cement bond or fault. A range of predictions was provided to describe the range in estimated ultimate recovery of a single typical well. The completion design will cater for active dewatering of the well.Because great uncertainty exists about the propensity to water production, the optimal well design will be flexible enough to allow for de-watering throughout the life of the well.

It is the responsibility of oil and gas operators to recycle or dispose of drilling cuttings in a safe and environmentally friendly manner. Environmental regulations are very strict in establishing that green operations and cutting re-injection be as clean and friendly to environment as possible despite the associated challenges and cost. It is the preferred technique by the majority of international companies. Cutting re-Injection operations include grinding down the drilling cutting to small particle sizes and mixing them with a water-based fluid (mud, water, gel) to form a slurry. The slurry is then pumped under high pressure into a disposal formation where fractures can be initiated and propagated. Existing wells can be used as appropriate by targeting watered-out formations far from hydrocarbon- bearing zones; sometimes operators drill new wells purely for cutting reinjection purposes. The main sources of uncertainty include reservoir heterogeneity, permeability, pore throat size and fluid leakoff rates into the formation. The optimum scenario is to pump the cutting re-injection slurry into a very high permeability formation where screening out, plugging or well packing is unlikely, assuming solids are suspended and are completely lost into the formation. This scenario can only be feasible if the formation pore throat size is much larger than the solid size. This paper presents how to conduct risk assessments for all possible scenarios considering all sources of uncertainties. The paper also shows that under some circumstances it is better to pump the cutting slurry into a very tight formation, such as shale (closed system), than a permeable formation with a high degree of uncertainty where screenout potential risk is most likely.

Standing seam panels are offering un‐competed metal roofing solution with respect to water leakage prevention. Therefore, need to develop new Standing Seam profiles and alternative seaming techniques is rising now a days. However, standing seam panels wind uplift capacities have no specification or closed form equations and tests are usually needed in order to evaluate clip and seaming capacities. Testing an assembly of the standing seam panels in air chamber equipped with adequate air bumps is usually done for this purpose. However, same types of lab equipment are not available in many developing countries and shipping assemblies overseas for testing is costly. Consequently, developing testing method that is economic and fairly accurate is needed. In this study, standing seam clip connection is designed and tested separately in universal testing machine. The designed details are simulated numerically using nonlinear finite element model. Cladding sheets are modeled using hybrid shell & solid elements while connecting fasteners are modeled using beam elements, Results of the developed testing techniques are compared with that of large scale standing roof system tested using air bump chamber. Failure loads of the isolated clip connection are compared with that in the large scale panels failure modes.