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.
The Permian Basin of West Texas and New Mexico is a prolific brownfield that produces from numerous clastic and carbonate horizons. Some of these reservoirs are composed of several separate thin tight sands ranging from 6 to 11 feet. Historically, these thin bed formations were bypassed because of lack of production in vertical wells. To economically exploit hydrocarbon reserves from these thin beds, maximum reservoir contact within a single layer or commingled across reservoir layers off a horizontal well path is necessary. To maintain or steer the well within these thin reservoirs, distinct log responses across the reservoir is needed for lateral correlations and well trajectory steering. Unfortunately in the thin reservoir realms such as those encountered in the Permian Basin, a lack of contrast in log measurements, such as gamma ray and resistivity, often results in poor geosteering decisions with the consequence of high costs in well construction. Advances in horizontal and LWD technology now offers real-time placement accuracy using proactive bed boundary mapping technology that incorporates a sophisticated arrangements of resistivity transmitter-receiver arrays. It is well understood in the technical domain that log measurements require a degree of change in formation log response for steering applications. However, in low log measurement contrast reservoirs, deep directional curve measurements are currently the optimum alternative for well positioning interpretation.
High water production is a major issue in horizontal oil wells, especially in longer laterals, because of the high drawdown from the heel to toe. In addition, the presence of heterogeneity along the lateral section can lead to uneven sweep of hydrocarbons which can result in poor recovery. To control the water production and achieve better sweep efficiency, ICDs have been introduced which balance fluid flux along the producing horizontal well. This paper discusses the feasibility and results of using integrated technologies such as ICDs along with rotary steerable drilling systems (RSS) and azimuthal logging while drilling well placement technology to achieve higher reservoir sweep efficiency. This case study is focused on a Gulf of Mexico (GoM) shelf horizontal well which was completed with prepacked screens. The well was sanded in and plugged after five years of high water production. A saturation log was run in the offset well which granted the viability to revisit this reservoir. Consequently, a new offset horizontal well was proposed and drilled next to the existing well to sweep out remaining reserves. For the new offset well, full field dynamic simulations were performed to evaluate attic placement methodology and optimization of Inflow Control Devices (ICDs) into the integrated design. The results illustrate that attic horizontal well placement is feasible using integrated drilling with ICD technology to maximize the sweep efficiency.
Unconventional shale gas reservoirs are known for low porosity, low matrix permeability, the lack of an obvious seal or trap, large regional extent, and, in most areas, are believed to be highly heterogeneous in nature. As a result, it is common practice to confirm the reservoir thickness, evaluate the shale gas rock properties and to determine horizontal shale gas targets using vertical or pilot offset wells. Horizontal wells are then drilled and stimulated to maximize reservoir exposure and enhance inflow production performance. Taking advantage of the high gamma ray activity found in most shale plays, a majority of horizontal wells are steered to stay within the defined target window using a non-azimuthal, averaged gamma ray measurement only. By relying on a single measurement, there is no fall back when the interpretation presents several possible scenarios. Additionally, a non conclusive interpretation will negatively impact the efforts of optimizing the learning curve across a field. Resistivity measurements complement gamma ray data as they provide an extra data set for correlation. However, azimuthal images from density measurements acquired in real time can offer structural dip authentication along the well trajectory to provide a higher level of accuracy to the modeled structure. By having a validated structural model, a higher level of confidence in real-time steering decisions can be gained. An accurate structural model is also an effective tool to aid completion designs, correlate formation properties, refine target delineation and provide a foundation for evaluating production logs and microseismic observations. The main objective of this paper is to demonstrate how structural modeling using only gamma ray in horizontal wells can lead to non-unique solutions that can be a potential cause of inconsistent reservoir interpretations and varied production, not only between hydraulic fracturing stages but also from well to well. Having sufficient measurements for formation evaluation, drilling and production results can be better understood and applied to enhance target selection, followed by accurate well placement within the selected target structure. This level of well placement accuracy will deliver consistent production results and provide a common platform for evaluating completion practices.
In shale plays where horizontal wells are often required to achieve profitability, a common industry practice is to start evaluation of a prospect by drilling vertical or low-angle wells. Extensive formation evaluation measurements, which are then used as points of reference are then run. Interpretation data acquired from vertical wells is used to describe the local reservoir and determine horizontal well placement objectives. Horizon depths may be adjusted for depth based on surface seismic or observations from other wells, otherwise formation properties in the horizontal are considered to be invariant. Acquiring formation evaluation measurements along the lateral is often considered to provide little additional value, are not worth the extra rig time, risk, additional cost, and difficulties associated with tool conveyance. These wellbores typically will be stimulated to test production or converted to a horizontal well via sidetracking. Horizontal wells are commonly steered using simple gamma-ray measurements correlated with the vertical pilot wells. Detailed examination has revealed that steering results for horizontal wells, using averaged gamma ray correlation techniques and subsequent structural modeling, yield non-unique solutions. This may result in less than optimum reservoir exposure over the drilled interval. With the integration of Logging While Drilling (LWD) technology into the Bottom Hole Assembly (BHA), real-time formation evaluation measurements provide key information for detailed rock property assessment across the target structure, consistent with pilot or offset well evaluation methods, and facilitate accurate well placement. Additionally, real-time and pseudo real-time LWD measurements have been successfully used for hazard avoidance, enhanced penetration rates reducing drilling time, and most importantly completion design optimization. While the LWD method offers some appreciation for the inconsistent rock quality and variable production results across wells, it also provides conclusive insight into the reservoir-production relationship. Understanding of this relationship provides for target refinement within the reservoir column and an optimized completion for an overall increase in reserve recovery. This paper investigates the use of gamma ray-only measurements only for evaluation and geosteering, and then details the geosteering application using more robust formation evaluation and the subsequent completion optimization. Results are verified using micro-seismic monitoring and production data within a shale gas play. In this manner, structural models, formation evaluation and completion designs are combined to form the technological foundation that can unlock the secrets for viable and sustainable shale gas development.
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