结合新一代井下传感器与高速有线遥测技术，RockSense可实时精确测量MSE，优化井眼轨迹，及时提供地层变化信息。 来自丨E&P 编译丨TOM 优化井眼轨迹是实现油藏采收率最大化的手段之一，工程师们通常利用现有技术来实现这一目标。然而，这些技术并不是最优技术，会影响油井的产量与效益。RockSense技术可提供钻头处的地层界面识别功能，为工程师们提供地层变化的实时信息。该技术将机械比能理论转化为实践。本文介绍了该技术的实际应用效果，并利用邻井的测井资料，验证了结果的可用性与准确性。 MSE应用方法 MSE表示在地层中钻出一定长度的井眼所需的能量，这揭示了地层的组分。随着地层可钻性的变化，破碎它所需的能量也随之变化。尽管该理论有可能彻底改变钻井精度，但迄今为止，可用技术匮乏，MSE的实际应用也受到了限制。这是因为精确计算MSE需要实时测量井下钻压（WOB）与钻头扭矩。 通常这些数据都是依据井口测量数据，考虑浮力与摩擦的影响，再进行经验校正。然而，校正带来的噪点，几乎大于由于地层特征不同而引起的MSE变化。近年来，技术的进步使得井下测量钻压与钻头扭矩成为可能，但泥浆脉冲的带宽限制，又一次成为了MSE成功应用的拦路虎。 最新一代连续油管钻进的底部钻具组合(BHAs)，集成了井下传感器与高速有线遥测技术，为最终实现高精度的MSE测量提供了技术平台。 它的工作原理是在钻进时测量泥浆马达的输入功率，以了解所钻岩石的类型。该技术测量压差与流速。知晓泥浆马达的主要作业参数，即可给出关于压力与流速的功率表达式。随着钻进的深入，这种功率被整合在一起，可得到每英尺钻进作业所消耗的能量，因此就能获得地层变化的相应指标。 通过持续监控扭矩、钻压、压力与机械钻速，RockSense可实时提供钻井作业的相关信息。此外，得益于有线遥测具有较高的数据传输速率，每钻一英尺可进行多次测量，作业者能够获得英寸级别的分辨率。随着钻进作业的进行，该技术可帮助作业者了解更多井下信息。 优势 由于缺乏精确测量MSE的能力，传统上使用两种地质导向方法。第一种方法，使用传感器测量诸如伽马、电阻率、孔隙率等系数。虽然这些传感器成熟、可靠且一致，但传感器在底部钻具组合上的位置却很尴尬。钻头是位于BHA的底部，可定向传感器组件却可能位于泥浆马达上部*至*米（**至**英尺）的位置。直到钻头深入地层*至* 米，地层特征才会明显变化。即使不会影响产量，但钻进非产层所浪费的作业时间，也会影响项目的工期。 第二种地质导向方法是岩屑录井分析。然而，循环岩屑至地面、获取岩屑、分析前的准备工作所耗费的时间，都会造成延迟。同样，在地面收到确认之前，早已钻穿了目的层，缩短了完成地质导向作业可用的垂深。环空中岩屑的分散（不同大小与密度的岩屑的上返速度不同），也会对深度分辨率造成不利影响。 这两种方法毫无疑问都代表了当时最好的技术，但这两者终究会被现有的技术所淘汰。 案例分析 第一个案例是北美某口连续油管钻出的侧钻井。该井是该地区的首口水平井，目的是通过增加油藏接触面积来增加产量。 作业者利用三维地震技术对地层进行了评估，并确定出一个可能充当圈闭的地下隆起。设计原则是控制轨迹在地层顶端下方约*.*米（**英尺）处，并保持井斜角，使井眼一直处于地层中。预估的油水界面位于地层顶端下方**米（**英尺）处，如果井眼进入了水层，将会显著影响该井的经济效益。因为仅依靠地震深度无法提供所需的精度，所以应用了伽马传感器来测量井深。在建井阶段，利用单相流钻井液来钻进该井段。 如图*，利用RockSense处理作业中采集的数据，在绘制孔隙度与垂深（TVD）关系图时，密度测井曲线与RockSense曲线有着惊人的相似性。 第二个案例是北美一口连续油管欠平衡钻进的页岩气井，如图*。在该井*.**寸水平段的钻进作业中，钻井液中混入高达**%的氮气，以尽量减少地层损伤。其作业目的是将井眼控制在确定的储层中。利用RockSense对历史数据进行处理，识别出目的层下方的实际井眼轨迹。如果实时应用该技术，即可采取更为主动的导向策略，避免井眼钻出地层。利用RockSense技术，首次实现了钻头处地层边界的识别。这些信息是实时传输的，而且这些数据代表了钻头位置处（不是钻头上方）的情况，从而司钻能够在目的层中钻出更多进尺，钻出最优井眼轨迹。应用该技术提高了采收率，提高了初始产量，并显著增加了项目的经济效益。The need for optimal wellbore placement to maximize recoverable reserves is a given, and engineers have always harnessed the available technologies to do this. However, the technologies have fallen short of the optimum, impacting productivity and profitability. RockSense provides at-bit bed boundary identification, giving engineers real-time information about a formation boundary at the point of transition. The technology turns the theory of mechanical specific energy (MSE) into practice. This article reviews what this new technology can achieve in practice using two historical datasets, both based on the availability of conventional logs from adjacent wellbores for corroboration. The first dataset is from a coiled tubing (CT) drilled sidetrack of a well in a densely drilled site in North America. No horizontal wells had been drilled in the area previously, and the objective was to increase production through increased reservoir contact. The operator used *-D seismic to evaluate the formations and identified a subsurface ridge that could be acting as a trap. The well path was planned to pass about *.* m (** ft) below the formation top and track the formation by holding inclination. The oil-water contact was believed to be ** m (** ft) below the formation top and, if entered, would significantly impact the well economics. Gamma ray sensors were used for depth correlation because relying on seismic depth alone would not provide the accuracy required. The hole section was drilled using a single phase fluid in the build section. In combination with the QuikSurvey service, shared power through batteries of the VPWD* collar-mounted verified pressure-while-drilling service enables pumps-off direction and inclination surveys to further minimize surveying time. As a result, the OmniSphere RGM service significantly reduces borehole instability risks and stuck pipe incidents while increasing the efficiency in survey time—especially in highly permeable formations. Running RockSense on the data gathered during this job revealed compelling similarity in the shape of the density logs and the RockSense trace when plotting porosity against true vertical depth (TVD) (Figure *). The second dataset involves underbalanced CT drilling in a shale gas well in the U.S. (Figure *). In this instance, a *?-in. lateral was drilled using a mixture of up to **% nitrogen to minimize formation damage. The aim was for the wellbore to stay within an identified formation layer. Processing the historical data using RockSense identified substantial footage drilled below the target formation. If the technology had been used in real time, a more reactive steering strategy could have been followed to avoid exiting the formation. Operation MSE is the energy required to drill a length of the hole in a formation, which reveals the composition of the formation. As the drillability of the formation changes, so does the energy required to drill it. Although the theory had the potential to revolutionize drilling accuracy, the technology available until now has meant the practical application has been limited. This is because calculating MSE accurately requires real-time measurement of downhole weight on bit (WOB) and torque. Historically, these were derived from surface measurements, with empirical corrections applied to the effects of buoyancy and friction. However, the noise of the corrections was almost always louder than the MSE signal changes caused by differing formation characteristics. More recently, technology advances have made downhole measurement of WOB and torque possible, but mud pulse bandwidth limitations have imposed severe constraints on the definition that can be achieved. The latest generation of CT drilling bottomhole assemblies (BHAs) features integrated downhole sensors and high-speed wired telemetry to provide a technology platform that finally makes high-definition MSE measurements possible. It works by measuring the power input to the motor as the hole is being drilled to gain an understanding of the type of rock being drilled. The technology measures differential pressure and flow rate. With knowledge of principal operating constants for the motor, an expression for power regarding pressure and flow rate can be written. This power is integrated as the hole progresses, giving a value of energy expended per foot of hole drilled and therefore giving a relative indicator of the changes in formation. By continually monitoring torque, WOB, pressure and ROP, RockSense provides information about the formation being drilled in real time. Further, because wired telemetry has a high data rate, multiple measurements can be made for every foot drilled, and operators can gain inch level resolution. It opens a new window on the downhole environment as drilling progresses. Considering the advantages In the absence of the ability to accurately measure MSE, two geosteering methods have traditionally been used. The first method uses sensors measuring factors such as gamma, resistivity and porosity. Although these sensors are mature, reliable and consistent, the position of the sensor along the BHA is a significant drawback. The drillbit sits at the bottom of the BHA, but the directional sensor package sits perhaps * m to * m (** ft to ** ft) farther back, behind the mud motor. A change in formation characteristics is not evident until the bit is * m to * m farther into the formation. Even if there is no productivity impact, the time spent drilling unproductive formation impacts the project’s bottom line. The second method for geosteering is by cuttings analysis. However, the time taken to circulate cuttings to surface, capture them and prepare them for analysis inevitably means a delay. Once again, the formation of interest is penetrated before confirmation is received at the surface, reducing the TVD available to complete a steering action. Dispersion of cuttings in the annulus (different sizes and densities travel at different speeds) also can adversely affect depth resolution. Both methods undoubtedly represented the best available solution for their time, but both are superseded by the technology now available. With RockSense, at-bit bed boundary identification is possible for the first time. The information is delivered in real time and because the data are representative of conditions at the bit—not behind it—the driller can deliver an optimally placed wellbore with more meters drilled in the target zone. The result is improved lifetime productivity, higher IP and substantially improved project economics.