BackgroundCertain early-phase clinical trials have suggested that bone marrow-derived stem cell transplantation might improve left ventricular function in patients with non-ischaemic dilated cardiomyopathy (NIDCM), whereas others trials have revealed no benefit from this approach. We sought to evaluate the therapeutic effects of bone marrow-derived stem cell therapy on NIDCM.MethodsWe searched the PubMed, Embase, and Cochrane Central Register of Controlled Trials (CENTRAL) databases (through February 2016) for randomised controlled clinical trials that reported on bone marrow-derived stem cell transplantation for patients with NIDCM with a follow-up period ≥12 months. The co-primary endpoints were changes in mortality rate and left ventricular ejection fraction (LVEF); the secondary endpoints were changes in the 6-minute-walk test (6MWT) and left ventricular chamber size. Seven trials involving bone marrow-derived stem cell therapy that included 482 patients satisfied the inclusion and exclusion criteria.ResultsSubjects who received bone marrow-derived stem cell therapy exhibited a significant reduction in mortality rate (19.7% in the cell group vs. 27.1% in the control group; 95% confidence interval (CI) –0.16 to –0.00, I 2 = 52%, p = 0.04). Bone marrow-derived stem cell therapy tended to produce LVEF improvement within 6 months (1.83% increase; 95% CI –0.27 to 3.94, I 2 = 74%, p = 0.09) and significantly improved LVEF after mid-term (6–12 months) follow-up (3.53% increase; 95% CI 0.76 to 6.29, I 2 = 88%, p = 0.01). However, this therapy produced no significant benefit in the 6MWT (p = 0.18). Finally, the transplantation of increased numbers of stem cells resulted in no observable additional benefit with respect to LVEF.ConclusionsBone marrow-derived stem cell therapy might have improved prognoses and appeared to provide moderate benefits in cardiac systolic function at mid-term follow-up. However, this therapy produced no observed improvement in exercise tolerance.

Recently a combined application of two technologies, horizontal drilling and multi-stage massive hydraulic fracturing (HF) has made vast resources of shale gas commercially viable. The HF is a well-established reservoir stimulation technique, which has been developed over the last half century. There are reliable tools for designing HF in conventional reservoirs, in which a planar HF is assumed.On the contrary, in shale gas fracturing, micro-seismic observations have illuminated a complex internal structure resulting from the interaction of the induced hydraulic fractures with natural fractures. It is widely speculated that the stimulated natural fractures make a significant contribution to the gas production.The mechanics of the interaction between multiple fractures during a HF treatment is very complicated. In this paper we present the results of state-of-the-art modeling of an explicit interaction between a propagating hydraulic fracture and a statistically generated discrete fracture network. A sensitivity study reveals a number of interesting observations including importance of initial fracture conductivity for growth of the fracture system, effect of the dilation angle on the generated conductivity and net pressure and uneven distribution of fracture aperture that is critical for proppant placement.This work strongly links the production technology and geomechanics and suggests an approach for modeling and designing HF treatments in unconventional shale gas plays.

The recovery factor from tight gas reservoirs is typically less than 15%, even with multistage hydraulic fracturing stimulation. Such low recovery is exacerbated in tight gas condensate reservoirs, where the depletion of gas leaves the valuable condensate behind. In this paper, three enhanced gas recovery (EGR) methods including produced gas injection, CO 2 injection and water injection are investigated to increase the well productivity for a tight gas condensate reservoir in the Montney Formation, Canada. The production performance of the three EGR methods is compared and their economic feasibility is evaluated. Sensitivity analysis of the key factors such as primary production duration, bottom-hole pressures, and fracture conductivity is conducted and their effects on the well production performance are analyzed. Results show that, compared with the simple depletion method, both the cumulative gas and condensate production increase with fluids injected. Produced gas injection leads to both a higher gas and condensate production compared with those of the CO 2 injection, while waterflooding suffers from injection difficulty and the corresponding low sweep efficiency. Meanwhile, the injection cost is lower for the produced gas injection due to the on-site available gas source and minimal transport costs, gaining more economic benefits than the other EGR methods.

Tight oil production is emerging as an important new source of energy supply and has reversed a decline in US crude-oil production and western Canadian light-oil production. At present, the combination of the multistage hydraulic fracturing and horizontal wells has become a widely used technology in stimulating tight oil reservoirs. However, the ideal planar fractures used in the reservoir simulation are simplified excessively. Effects of some key fracture properties (e.g., fracture-geometry distributions and the permeability variations) are not usually taken into consideration during the simulation. Oversimplified fractures in the reservoir model may fail to represent the complex fractures in reality, leading to significant errors in forecasting the reservoir performance. In this paper, we examined the different fracture-geometry distributions and discussed the effects of geometry distribution on well production further. All fracture-geometry scenarios were confined by microseismic-mapping data. To make the result more reliable and relevant, a geomodel was first constructed for a tight oil block in Willesden Green oil field in Alberta, Canada. The simulation model was then generated on the basis of the geomodel and history matched to the production history of vertical production wells. A horizontal well was drilled in the simulation model, and different fracture-geometry scenarios were analyzed. Results indicated that the simulation results of simple planar fractures overestimated the oil rate and led to higher oil recoveries. In addition, if the secondary fracture can achieve the same permeability as the main fracture, a hydraulic fracture with branches can increase the well production (e.g., Scenario 2 under the conductivity ratio of 1:2) because of a larger effective contact area between matrix and fracture. Secondary fractures with low permeability can decrease the well productivity compared with wells with biwing planar fractures. Furthermore, the effect of hydraulic-fracture geometries on the cumulative production of the wells with higher main-fracture conductivity was more significant compared with those with lower main-fracture conductivity.

No abstract