Located in offshore South China Sea, Ledong high-pressure/high-temperature (HPHT) gas field has entered the appraisal phase after the first discovery was announced in 2015. The pressure gradient of the main target zone is close to 2.2 g/cm3 whereas the top formation is approximately 1.8 g/cm3; the sand packages are separated by a variable shale layer thickness. To avoid kicks, mud losses, or other drilling problems, mud weight must be adjusted accordingly to preserve the well integrity. Hence, the main objective for this hole section is to stop drilling above the main target sand and set casing to isolate the formation with different pressure gradient. An innovative look-ahead technology based on deep electromagnetic measurements was used to predict the formation change ahead of bit in real time to reduce the drilling risk. After review of the technical and geological challenges encountered in this field, this paper will discuss the successful approach taken to detect formation changes using the new technique. After the shale layer above the target sand has been identified in real-time, drilling will stop above the high-pressured sand to set casing. In addition, the authors will also describe the bottom hole assembly (BHA) configuration and measurement selection in the planning phase to ensure the success of this well. The real-time interpretation of look-ahead measurements enables boundary detection ahead of the bit at distances ranging from 3 to 20 m in this example. The depth of detection depends on the resistivity contrast between formation, layer thickness, presence of laminations, and the transmitter-to-receiver distance. The application of the innovative look-ahead technology has helped to Reduce the drilling risk by detecting formation change ahead of the bit Accurately identify casing shoe position to ensure well integrity Eliminate extra casing string, which will directly increase the well construction cost Avoid unnecessary operation adjustments and improve drilling efficiency Clear prediction of the resistivity profile ahead of the bit enables proactive decision making while drilling. This additional information has removed the need to consider the possibilities for different scenarios and the extra circulating time taken to make decisions among stake holders. The successful implementation of the look-ahead technology and the application in the HPHT well has led to reduction in overall nonproductive time by reducing drilling risk and improving drilling efficiency. This innovative technique changes the real-time decision-making process while delivering a new way to manage drilling risk.

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.

A common practice in shale plays is to evaluate vertical boreholes with an extensive wireline logging program. Largely driven by cost, time and difficulty associated with acquiring wireline measurements in horizontal intervals, only data logged from the vertical hole is interpreted and used to define the reservoir profile for the horizontal target window. The horizontal wells are then steered based on simple gamma ray measurements by means of correlation against the vertical pilot wells. Detailed studies from a range of shale plays have revealed that the geosteering results for these wells using only gamma ray, are often questionable as it can provide non-unique structural modeling solutions.Integrating Logging While Drilling (LWD) tools into the Bottom Hole Assembly (BHA) enables formation evaluation measurements to facilitate accurate well placement and perform detailed reservoir characterization across the target structure. Additionally, LWD measurements have been successfully used to avoid drilling hazards, enhance rate of penetration to reduce drilling time, and optimize completion designs. Using limited data for horizontal well correlations often result in inaccurate structural interpretations. This inaccuracy complicates the understanding of production variations between wells. By employing LWD, the uncertainties can be narrowed to enhance trajectory placement and provide a better understanding of the reservoirproduction relationship. This relationship allows target refinement within the productive reservoir interval followed by an optimized completion for an overall increase in reserve recovery. This paper details the use of LWD measurements for accurate well placement, formation evaluation, and completion optimization within a shale gas play using an integrated shale gas solution.

The lower Minghuazhen is a shallow-water, delta-plain, sedimentary-deposit reservoir sand in Bohai Bay, China. It has relatively heavy oil in place that is high in viscosity. With the understanding that horizontal or multilateral profiled wells are the most favorable design to economically increase individual well production and reservoir drainage, an ambitious program was embarked upon to drill 11 of these wells in the first phase of a drilling campaign. Although the sand is well defined in offset wells and the structure had been interpreted to correlate between them, Phase I of drilling yielded disappointing results; and only 5 of the planned 11 wells were completed as planned. To guide the second phase of the development program in which multilaterals were still in favor, a different approach was necessary. The available 3D seismic data was reprocessed using frequency spectrum imaging to better understand target definitions. In addition, Phase I was analyzed in terms of drilling, operational procedures, processes, tools selections and well designs to identify root causes and to learn from them. These studies were then applied to overcome the cannel structural complexities, thus implementing the course of action for seven multilateral wells on Phase II. Introduction The main target interest for this oilfield is the lower member of the Minghuazhen Formation. It is generally characterized by complex reservoir distribution and poor crude oil properties. The main reservoir group is the shallow-water delta-plain sedimentary deposit (Fig. 1) consisting of river channels that are relatively narrow (generally less than 200m), dominant mudstone between river channels, poor sand connectivity, relatively thin single-sand layers (generally less than 10m) and fairly small quantities of sand body within the target interest (Fig. 2). The crude oil is characterized by high density and high viscosity below. Surface crude density (20ºC) 0.92–0.97 g/cm3 Viscosity (50ºC) 48.28–934.8 mPa•s Formation crude density 0.861–0.897 g/cm3 Viscosity 20.07–120 mPa•s In view of the above geology and reservoir characteristics of the oilfield, horizontal and multilateral well designs were needed to effectively develop this oilfield. In total, 182 development and injection wells were designed, of which 24 were horizontal; 11 in the Phase I drilling campaign and 13 more in Phase II. Phase I On the Phase I drilling campaign, a total of 11 horizontal wells were planned but only six of these were drilled and with five completed as designed. Of these five wells, only three were drilled with acceptable drainage lengths (Table 1). Based on these results, the remaining wells were either shelved or redesigned to directional type wells. Phase I studies revealed that the internal structure of the seismic reflection axes, which represents the sand columns, is highly complex. While drilling, some seismically interpreted sand bodies were favorably composed of sandstones (Fig. 3), some were composed of sandstone/mudstone laminations (Fig. 4), while others were fully non-reservoir compositions. Unfortunately, it was not possible to use seismic reflections to accurately predict for phase change occurrence where the physical properties of the reservoir degraded to non-reservoir properties.