Across many shale plays in North America, operators ask why production performance disparities exist among horizontal wells. For example, even though drilling and completion practices of a neighboring operator may be mimicked, significantly different production results are frequently observed. Several hypotheses have been presented on the subject with little consensus. In most of these wells, formation evaluation in the lateral section is limited to gamma ray. Using a single curve to model the structure leads to multiple solutions with no way to determine which one is correct. Accordingly, large uncertainties may exist in: 1) determining the relative geologic position of the wellbore, 2) placing perforation clusters, and 3) selecting the appropriate staging design and stimulation treatment for the resulting well placement.To produce wells that perform to their maximum potential, it is fundamentally necessary to understand both the placement of the lateral in the reservoir and the placement of the perforations in the lateral. To optimize these placements, some measurements must be taken in the lateral. Obviously, the value of understanding where to locate the lateral and the perforations must be greater than both the direct costs associated with taking these measurements and the risk weighted costs associated with deploying tools in the lateral. A way to acquire this information while mitigating many of the aforementioned concerns is logging while drilling (LWD). Some of the measurements that LWD can capture along shale laterals include borehole/azimuthal images, stress, and mineralogy. With these comprehensive LWD measurements, not only can the captured data be taken for future completion design and analysis, they can also be used while drilling the lateral to steer the wellbore towards a desired target more accurately than gamma ray only. This paper focuses on how lateral LWD measurements impact well placement, perforation selection, hydraulic fracture stage spacing, completion design, resultant production, and subsequent economics of horizontal shale wells. Practical LWD examples from the Eagle Ford and Woodford Shale plays are presented, along with their impact on the aforementioned subjects.In this paper principles of using LWD measurements and interpretation in a field development plan are described, including relating LWD data to additional functions such as completion design, microseismic hydraulic fracture monitoring, production monitoring, and production logging. Ideas on how to optimize the amount and type of LWD measurements are proposed. Lastly, the paper will examine the impact of LWD measurements on the overall economics of horizontal shale wells.

Scale formation in downhole tubular-flow passages can cause partial to complete plugging that will affect production or injection rates adversely. In an intelligent well completion in which the interval control valve (ICV) positions must be changed in order to control flow rate; the completion will become ineffective, if plugging of clearances prevents valve actuation. To mitigate these problems, a method to predict the potential rate of scale formation under realistic conditions has been developed. This paper describes this method, which allows prediction of tool performance under scale-forming conditions for downhole applications. This semi-empirical method uses chemical data and flow fields generated by computational fluid dynamics (CFD) models for downhole tools. Chemical data are obtained from laboratory tests on coupons using brines matching the chemistry of connate fluids. Tests in a high-pressure, corrosion-resistant vessel over a range of high pressures (100 to 10,000 psi) and high temperatures (75 to 150°C) to simulate downhole well conditions have been conducted. Two test sets each with fluid at rest and where an impeller generates low velocity in the reaction vessel were conducted, ranging from 4 hours to 4 days with scaling rates determined from coupon weight gain. Concentrations in the range of 50% to 125% of the typical connate fluid concentration were used. The laboratory test data are used with velocity field data to develop an artificial-intelligence-based mathematical model to determine scale formation rates. The model can be applied to any tool geometry as long as the operating conditions are within allowable limits of the model. The model also provides some insight into the mechanism of scale formation. To verify accuracy, scale formation in a 4.5-inch interval control valve was predicted at high-pressure, high-temperature conditions at a low flow rate. Laboratory tests on the valve matched the model predictions reasonably well, enabling Petrobras to design a better completion and fluid-handling system for a pre-salt well.

The application of horizontal drilling has made exploitation of oil from low matrix permeability, naturally fractured reservoirs feasible. However, enhancing recovery from this reservoir type presents a distinctive problem. The low porosity and permeability matrix is virtually unaffected by the fluids injected into the extremely high permeability fractures. These fractures are multileveled and range from large scale macro- to small scale micro-fractures. The effects that the presence of fractures on oil recovery due to water imbibition was studied. Both unadulterated and carbonated water imbibition tests were conducted on Indiana Limestone cores confined by a fluid pressure of 800 psi. Water was enriched with CO2 at a 500 psi carbonation pressure for the carbonated water cases. Magnetic Resonance Imaging (MRI) methods were used to study the effects that micro-fractures have on their surrounding rock matrix during oil production by water imbibition. The presence of micro-fractures revealed that several factors may assist oil displacement:Capillary forces drive water into the microfracturesIncrease in the surface area available for water imbibitionOil trapped in fractures can be displaced by this process.An adequate wettability facilitates the process Inclusion of CO2 improved oil recovery by:Increasing the oil mobilityA solution gas drive induced by the evolving CO2 when the system pressure is decreased below the carbonation pressure. The presence of micro-fractures wide enough to allow appreciable fluid movement, increased oil production when compared to production from homogeneous rock. Imaging studies showed water channels were formed within the fracture system. The presence of micro-fractures used the beneficial effects of capillary forces within the fracture system to create fluid paths that assist oil production. CO2 dissolved into the water being imbibed by the rock was found to accelerate oil recovery rates and increase ultimate oil recovery when compared to unadulterated water imbibition.