In this, the final of three blog entries about formation testing, I will cover the use of FTs for fluid identification and some advanced applications. In a demonstration that Baker Hughes employees occasionally do to illustrate these capabilities at trade shows we will actually pour either Coca-Cola®
Diet Coca-Cola® into the tool and differentiate the two based on the tool’s fluid identification capabilities. Far more powerful applications of formation fluids can be performed downhole at many different depths. Additionally, extended analyses can be performed on fluids recovered and brought to the surface.
Advanced applications include measuring vertical permeability and micro-frac testing for hydraulic fracturing optimization and for use in geomechanics.
The produced fluid recovered by formation testing can either be analyzed in-situ by the most advanced formation testers and/or recovered to the surface for additional analysis. Advanced FTs like the In-Situ Fluids eXplorer™ (IFX) available in the Reservoir Characterization Instrument™ (RCI) have multiple-channel visible and near Infrared spectrometers, methane detection devices, fluorescence spectrometers, refractometers and tools to calculate in-situ density, viscosity, sound speed, GOR and compressibility.
The figures below illustrate the typical responses of gas, oil and water under near infrared spectrometry. The 17 wavelength channels in X-axis indicate the color darkness of the flowing fluid at a particular wavelength.
Gas Oil Water
Once the mud filtrate contamination is minimized, the fluid flow is directed to the sample chambers for fluid collection. Typical fluid volumes that can be recovered to the surface range from about 500-20,000 cc with pressure ratings up to 25,000 psi. Samples recovered at near reservoir condition may prove invaluable in early reservoir characterization, particularly in layered reservoirs that are likely to be commingled during the completion or stimulation process. The authors have experienced situations with significant compositional variations obtained along a horizontal lateral in a reservoir previously believed to have been a common compartment.
The state-of-the-art FTs allow the operator to perform a “mini-DST” as well as tests to optimize hydraulic fracturing processes. In a standard DST, drillers isolate an interval of the borehole and induce formation fluids to flow to surface where they measure flow volumes before burning or sending the fluids to a disposal tank. The RCI™ tool, in particular the straddle packer module, provides similar functions to DST but on a wireline and at a smaller scale.
While the mini-DST is less expensive than a conventional DST, it also provides a significant safety advantage in that fluids are not produced to the surface. Cost benefits come from more economical downhole equipment, shorter operating time and the avoidance of any surface handling equipment. There are no problems of fluid disposal, no safety issues and no problems with environmental regulations. The mini-DST investigates a smaller volume of formation due to smaller packed-off interval and withdraws a smaller amount of fluid at a lower flow rate. Mini-DSTs can be applied to individual hydraulic flow unit to characterize its flow properties which could be a significant input in understanding and quantifying the reservoir heterogeneity. How many layers have the same fluids? This is in contrast with conventional well testing which provides average properties of all units and does not characterize reservoir layer fluid heterogeneity.
The pressure transients measured during the drawdown or buildup periods are interpreted to obtain the reservoir parameters. The pressure transients obey the same laws of physics as those measured during a conventional DST or well testing. Therefore, they can be analyzed and interpreted the same way. As a result, mini-DST conducted by wireline tools such as the RCI can provide reservoir permeability, assessment of formation damage (skin factor) and formation flow capacity as well as single-phase fluid sampling at in-situ conditions.
In a homogeneous layer, there are three flow regimes observed in a mini-DST: Early radial flow around the packed-off interval, pseudo-spherical flow until the pressure pulse reaches a boundary, and finally total radial flow between upper and lower no flow boundaries. Rarely are all three seen because tool storage effects can mask the early radial flow, while the distance to the nearest barrier determines whether or not the other regimes are developed during the test period. It has been common to observe a pseudo-spherical flow regime, and occasionally total radial flow in buildup tests (below).
To analyze pressure and rate response during pressure testing, it is necessary to have knowledge on the nature of the formation and the fluids therein. For the packer configuration, an analytical model for a partially completed well with storage and skin is used. The partially penetrating well model with homogenous reservoir behavior assumes uniform reservoir thickness, h, and porosity,f, with the well completed over a limited section, hw. The distance from the center of the isolated section to the bottom of the reservoir is designated as Zw.
On a log-log plot of the pressure derivative versus a particular function of time, spherical flow is identified by a negative half slope and radial flow by a stabilized horizontal line. Tool storage includes the compressibility of the fluid between the packers. A common model is to relate the sandface flow rate, qsf to the measured flow rate, q and the rate of change of pressure by a constant, C. The very early part of a buildup is dominated by wellbore storage, also called afterflow. C can be estimated from the rate of change of pressure at this time. Skin due to partial completion and formation damage can be calculated separately using the pressure and derivative data together.
For a very short time during the early fluid flow, it is expected to have radial flow due to thickness of the isolated zone (kxy× hw). It is unlikely to observe this flow regime in most tests because it might be masked by the tool storage effect in early time. The spherical flow regime, which represents the geometric mean of three directional permeability (kxyz), is the dominant flow regime in early time with straddle packer configuration. Flow regime becomes radial once the flow is restricted by top and bottom no-flow boundaries. The radial flow represents the product of horizontal permeability and reservoir thickness (kxy× h). The observation of both spherical and radial flow regimes in a mini-DST provides opportunity to calculate both spherical permeability (kxyz) and horizontal permeability (kx) and consequently the vertical permeability (kz) from the integration of both parameters.
Permeability anisotropy (kz/kx) is an important parameter for coning studies and completion/perforation policy determination in vertical wells. It is also one of the key factors influencing the production performance in horizontal wells. It is usually impossible to determine the vertical permeability in conventional well testing. Vertical interference test (VIT) performed by the RCI provides unique information on horizontal and vertical permeability of the tested formation in reservoirs. In a VIT, the combination of the straddle packer and conventional probe is used to conduct the test. A single probe or a combination of probes can be run directly above or below the Straddle Packer to collect pressure responses generated by the fluid flow within the straddle packer section.
The time required the pressure transients to propagate from the source to the observation probe is functions of the storativity and vertical permeability. For a given reservoir fluids and formation rock conditions the storativity can be calculated and considered constant. The simultaneous analysis of pressure transients from the source and observation points provides the unique calculation of kz values for the distance between two packers. Horizontal permeability (kx), skin factor and productivity index are also calculated in a VIT.
Micro-frac testing (MFT) is performed in vertical wells with the RCI Straddle-Packer module to determine stress and fracture gradient in reservoir and/or caprock formations for well injection plans, gas storage, or geomechanics-related issues and fracture closure pressure for in-situ stress determination. Instead of producing reservoir fluids, fluids are injected between straddle packers to create a small hydraulic fracture in the formation. After a brief pumping period that extends the created fracture, fluid injection is ceased and pressures are observed during the closure of the created fracture. Further pumping and shut-in periods are used to characterize certain rock properties and the minimum compressive stress. These properties are used in the design and analysis of subsequent stimulation treatments or geomechanical interpretations. Petroleum geomechanical models are used to optimize wellbore stability, pore pressure prediction, manage subsidence, etc.
You can learn about Baker Hughes technology and our Fluid Charcterization and Testing services including the In-Situ Fluids eXplorer (IFX) service and the SampleView service on the Baker Hughes website where you can also connect with our technology experts.
As an integral part of the Baker Hughes’ Reservoir Characterization Instrument™ (RCI™) service, the Baker Hughes SampleView service delivers real-time measurements of fluid type and mud-filtrate contamination. SampleView, combined with precise flow control, captures single-phase, low-contamination samples. Real-time fluid type and contamination measurements are critical to obtaining quality PVT samples.
Our SampleView service offers real-time, near-infrared spectra in 19 channels ranging from 400-2000 nm of the fluid pumped through the RCI tool. Two of the 19 channels are dedicated to methane peak detection and can be used for estimating gas/oil ratio (GOR).
In-depth information about downhole fluids
Our SampleView service delivers fluorescence spectra and continuous refractive index for salinity estimates. By monitoring these combined tool responses, reservoir fluid samples are collected with minimal contamination.
High-quality samples are essential for making intelligent completion decisions and for conducting PVT analyses. Our real-time FTA Forecast™ software allows the engineer to calculate an estimation of sample purity at individual depths. A full-range selection of SampleView measurements can be used as input to the analysis. The software graphically displays the estimations of sample purity at any given depth.
Our SampleView service’s refractive index measurement identifies fluid types and contamination monitoring. This continuous measurement enables more accurate oil-based mud (OBM) filtrate contamination monitoring and detects the presence of gas. As the refractive index of various fluid types is significantly different, it’s easy to distinguish between gas, oil, and water. The refractive index measurement can also be used as an input in the FTA Forecast analysis.
Through the use of a downhole ultraviolet lamp, a measurement of hydrocarbon fluorescence is acquired over five different wavelengths. This measurement aids in the hydrocarbon typing process based upon fluorescence spectrum and differentiates between light crude oils and condensates.