No abstract

Drill Pipe conveyance (TLC/PCL) of wireline logging tools or Logging While Drilling (LWD) is usually required for high deviation / high differential sticking risk logging scenarios. These are costly in terms of rig time and service company costs. This paper details how a full suite of high-quality open hole log data was obtained on wireline in a high angle 16,500ft wellbore utilizing a new conveyance system and a polymer-locked high strength cable. The new conveyance system, utilizing wheeled carriages and a holefinder with nose angled upwards, takes a holistic approach to tool conveyance, reducing drag while ensuring both correct tool orientation and optimum contact and standoff for each logging service. Management of tool centers of gravity relative to the wheel axes ensures correct orientation. The reduction in friction due to wheeled carriages vs weight and cable load is modelled before the operation in order to ensure successful runs, both into and out of the wellbore. Polymer-locked high strength cable significantly increases maximum safe pull capability and enhanced data transmission technology allows faster logging speeds, greater rig time efficiency and reduced sticking risk. The wheeled carriage system enabled conventional logging in a high angle well, minimized stick-slip and reduced differential sticking risk. The unique holefinder prevented tool hold up during descent. The Vertical Seismic Profile (VSP) run (the only run not able to utilize the system due to tool size and design) was held up on a ledge above the lowest reservoir of interest. The high strength cable allowed safe retrieval of tools (over-pull > 6000lbs) in one particularly sticky zone. In a world first, an array sonic tool was centralized through management of weighted and eccentralized tool sections using bespoke wheels. This eliminated the drag inherent to traditional methods of sonic centralization (centralization using powered calipers and/or spring centralizers), resulting in excellent data quality. Nuclear Magnetic Resonance logs were obtained by orienting the tool sensor with wheels which utilized tool weight to provide sensor application force. This removed the need for additional centralizers, resulting in data devoid of stick-slip artefacts (an issue in previous wells). The formation fluid sampling run was conveyed on drill pipe, taking 6 days of rig time. There are further significant efficiency gains to be had on future operations by using the new conveyance system on sampling tools (operators have already moved in this direction in the Gulf of Mexico).

Pore network complexity in carbonate reservoirs is the result of heterogeneous pore size distributions, diagenesis and fractures. Fluid movement through such reservoirs is difficult to model, and permeability depends on the scale considered. Existing permeability computations are empirical in nature, and simply estimate average permeability curves that are hard to upscale. A novel approach for azimuthal and dynamic permeability estimation that preserves formation heterogeneity information is presented through a case study of Jurassic carbonate reservoirs. First, existing petrophysical procedures are extended to take advantage of most Logging-While-Drilling (LWD) data being available in azimuthal fashion as images, to produce azimuthal lithology, porosity and fluid saturation images that retain all the information present in the original LWD images, instead of average results. A new azimuthal permeability image, derived from invasion dynamics, complements the volumetric petrophysical analysis. In general, while drilling, mud filtrate volume is highly correlated to formation permeability, time after bit (TAB), differential pressure, fluid viscosity and mud properties. Therefore, formation permeability can be inverted from the knowledge of all the other parameters. Mud filtrate volume can be computed as an azimuthal image from collocated azimuthal resistivity images at multiple-depths-of-investigation (MDOI), and TAB of such images is readily available as a log. Differential pressure and fluid viscosity can be measured. Finally, mud properties are calibrated to achieve the best match against LWD formation pressure testing stations. A method to compute horizontal (KH) and vertical permeability (KV) from the azimuthal permeability image is also discussed. LWD data from several horizontal wells were processed and the benefits of displaying the resulting volumetric petrophysical analysis images in 3D are discussed. The processed resistivity images confirm heterogeneous /complex formation texture, with thin layering (~ 1 to 3" thickness), different vugs' size and type (within beds, along bedding planes, or along fractures), burrows patterns, and open, closed, and drilling induced fractures. The formation permeability image results match oriented formation tester data with ~ 95% confidence, over the entire range of measured permeability (~ 0.2 mD to 2 D). Image-derived high-resolution KH and KV were computed at different scales, taking into account true bed thickness (TBT) computation. The High-resolution resistivity images were also processed to study fracture distribution, by fracture type, and to extract fracture attributes. KH and KV can be used as direct input for smart completion design with Inflow Control Devices (ICDs), or Interval Control Valves (ICVs). The azimuthal volumetric petrophysical analysis and formation permeability results presented in the case study represent a step improvement in heterogeneous carbonate reservoir characterization, and constitute the first quantitative application of invasion physics while drilling to dynamic permeability estimation.

This paper presents the successful use of LWD NMR and LWD resistivity image log technology to meet the challenge of placing wells in a thin reservoir with lateral facies variation without the use of radioactive sources and with simultaneous data acquisition to evaluate the wells and design their downhole inflow control devices (ICDs). A series of horizontal producer wells were planned in a thin reservoir with lateral facies variation. After drilling the wells they were completed with downhole ICDs. Optimum placement of the wells within the reservoir and data acquisition to evaluate the wells and design their completions was achieved without the use of radioactive sources, as these created an unacceptable drilling risk. Rapid and accurate processing of the data in real time and subsequent design of the ICDs was required to enable the completions to run in a timely fashion. The NMR permeability was normalized using the new calibration parameters that were developed by integrating NMR results with core data, and the same relationship has been tested in other lateral wells. Real-time NMR total porosity played a significant part in facilitating effective geosteering and well placement without the drilling risks associated with radioactive sources. In addition, the NMR provided a porosity distribution that was used to estimate a permeability index. This index was normalized using core permeability available from offset appraisal wells. The core and NMR log data in the offset wells were combined to derive the parameters for an NMR permeability relationship. The standard volumetric analysis results and the permeability index were used for identifying reservoir flow units using crossplots of normalized flow capacity versus normalized storage capacity (modified Lorenz Plots). These results were then used to develop the parameters for the ICD completions. High resolution LWD image log data was incorporated to select the best possible sections in the wells for isolation of the ICD segments. Following completion and stimulation, multiphase PLTs were run across the ICD compartments to evaluate the wells. These results were then compared against expectations and used in subsequent well completion designs. The results of the wells presented show that the chosen methodology enables the successful placement and completion of horizontal wells in this reservoir. Decisions about ICD completion design can be made in a timely fashion just after the drilling phase is complete, avoiding rig downtime. This approach has become the default procedure for the field and will be used for the bulk of the remaining producer wells in the reservoir.

Analysis of single-well sonic measurements to determine formation TI elastic parameters has traditionally been done using deterministic models with multiple, simplistic assumptions using only vertical or horizontal wells with flat structural dip. Here a probabilistic Bayesian-type inversion method is shown, which provides a flexible solution for any wellbore orientation solving for all five TI (transversely isotropic) parameters. This inversion is guided by prior information, which may be; core tests, borehole seismic survey results, offset well data or a public database. The approach demonstrated here uses prior information of TI elastic properties to determine a consistent model at each depth. The inversion uses all sonic slownesses, compressional, fast and slow shear, as well as Stoneley shear and density to provide a continuous output of Thomsen's parameters and anisotropic mechanical properties at each depth. The results are consistent with offset well data as well as walk-above VSP velocities obtained in the same well. This technique was applied on a prominent and thick shale formation, which is present throughout UAE. Most of the wells drilled in UAE penetrate through this shale formation which is locally unstable for drilling, and is a prominent seismic reflector which directly overlies the reservoir. Accurate geomechanical characterization of this shale formation is critical as more wells are drilled at high angles with the application of full 3D finite-element modeling. Similarily the velocity models used for pre-stack depth migration (PSDM) and seismic well tie require accurate anisotropic TI parameters. This workflow is new and applicable to any well orientation or structural dip and yields results that are consistent with offset sonic and borehole seismic measurements. Application of this method will have a profound impact on geophysical velocity and geomechanical model building methods and results.