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Advanced Workflow Package for Shale Assets Developed

The growth in unconventional resource plays in the past several years has produced a burgeoning need for new software tools for organic shales. Geoscientists need tools to help them understand complex hydrocarbon generation, storage capacity, and migration paths in source rock reservoirs, enabling them to flag and map optimized pay. Engineers need tools to help them define optimum techniques to deliver the most shale gas and oil to the market and enable them to build the best reservoir models to exploit these resources. And for unconventional resource development to proceed as it should, these tools must work together in a common framework.

An advanced integrated petrophysical evaluation software package, based on a calibrated workflow, was recently developed by Halliburton for organic shales. The concept behind it was to bring all the requisite pieces of an exploration shale play analysis into a single vantage point for an asset team. This is critical when very few vertical exploration wells are used to define the economics of these resource plays before full-scale horizontal development begins.

The software’s workflow modules encompass the following capabilities: total organic carbon (TOC) and organic maturity estimation; fluid and minerals evaluation; advanced saturation modeling; mechanical properties and brittleness; 3D stress and stress orientation; permeability; and pay analysis.

TOC Estimation and Organic Maturity

To define the resource volume, one needs to determine an accurate volume of organic kerogen present in the rock. To determine potential hydrocarbon type, the level of thermal maturity must be established. To solve for kerogen, the TOC measured by core pyrolysis can be calibrated to logs, using eight industry accepted correlations. Organic maturity, VRo, is measured by actual vitrinite reflectance or calculated from pyrolysis-derived Tmax (temperature between 300°C and 600°C that generates peak hydrocarbons from existing kerogen). This maturity value is used to make the final TOC calibration and predict hydrocarbon type.

Fluid and Minerals Evaluation

The heart of the volumetric analysis is its probabilistic solver. Total porosity in organic shales can only be resolved by logs when relative amounts of geochemically derived minerals are measured and combined with the TOC calculation.  Minimum requirements for this type of analysis include a triple combo log, neutron capture spectroscopy, and natural gamma spectroscopy. The software uses a probabilistic error minimization methodology to determine formation fluid and mineral volumes.

The idea is to construct theoretical logs that closely replicate actual logs. Tool response equations are expressed in terms of fluid and mineral volumes and their corresponding tool response parameters. Most response equations are linear. Some, such as neutron, conductivity, and certain acoustic equations, are nonlinear. The inclusion of additional evaluation tools, such as the dipole sonic travel time curves DTC (compressional velocity) and DTS (shear velocity), helps add coherence to the analysis, as long as the correct acoustic equations are used for harder rock-clay shales.

The analyst first constructs a “dry” rock model, which consists of the response equations, parameters, and constraints available for the input tools and includes TOC. The key to the entire analysis is solving only for those minerals that are actually found by core x-ray diffraction (or alternatively x-ray fluorescence). Key constraints relating relative abundances of the different types of clay mineralogy to one another, and to the base matrix silica or calcite, help complete the dry rock model.

When a good match of all measured log inputs for the dry rock model case has been achieved, the “wet” rock model case, which uses available resistivity inputs, is applied. While all conventional saturation models are supported in software, the Simandoux model has worked best in matching GRI core gas saturations because of its more robust handling of clay water response. Even with the best saturation equation, cementation “m” and saturation “n” constants must be adjusted lower to match core because only a portion of the internal pore surface has seen water as a wetting phase. Internal kerogen porosity has either oil or gas as a wetting phase, as it has never been exposed to water. Microfractures internal to the matrix, where migrating oil and gas have escaped internal kerogen containment, are also nonwater wet. This explains why conventional water saturation equations will fail unless calibrated to core.

Advanced Saturation Modeling: NMR and Dielectric Volumes

All organic shales exhibit both water and hydrocarbon wetting phases as a result of the varied porosity systems present in the rock. This makes it appropriate to apply resistivity independent saturation measurements, such as nuclear magnetic resonance (NMR) and dielectric porosity. These allow direct measurements of total fluid-filled porosity (NMR T1 time constant dimension) and total water-filled porosity (dielectric). The difference between the two is typically unflushed oil and gas that is picked up in TOC pyrolysis data as an S1 free hydrocarbon volume. It should be noted that the accuracy of the dielectric water porosity measurement depends on determining the mineralogy and water salinity.

The NMR porosity data is best viewed in a T1 dimension, as that time constant spreads out the measured porosity spectrum to twice the extent of that seen in conventional T2 porosity measurements. This allows a much more detailed analysis of the ultrasmall pores in the lowest part of the spectrum. Recent laboratory data show that in ultrasmall pores, gas exists in a restricted diffusion environment and will be detected earlier in a normal water signal range and not later in a T1 bulk signal. Even with that, a T1 measurement gives the analyst a much more robust spectrum in which an enhanced spectral BVI technique can be used to discriminate clay- and capillary-bound water from small amounts of free fluid.

The wet rock volumetric analysis can directly use all the discriminated NMR and dielectric porosity measurements. Clay-bound water can be constrained to what is seen from NMR. Total water can be constrained by a total dielectric porosity. A solved oil or gas volume can be constrained to the difference observed between NMR and dielectric porosities.

Mechanical Properties and Brittleness

Conventional vertical Young’s modulus and Poisson’s ratio are calculated from DTC and DTS dipole sonic data and are calibrated to static rock properties using surface core stress tests and analysis from small volume diagnostic fracture injection tests (DFIT) in cased vertical exploration wells. After final calibration to the DFIT analysis, the program determines fracture initiation pressure, fracture closure pressure, and closure stress gradient.

Since 2008, we have used the concept of shale “brittleness,” a simple ratio between Young’s modulus and Poisson’s ratio, as a technique to predict induced fracture complexity and enhanced surface area contact. It has been used extensively as a powerful fracture fluid system design tool and to aid in sweet-spot identification. This same technique is implemented as “pseudobrittleness” and is color palette calibrated to core-measured brine hardness.

Using directly measured DTC and DTS values, calibrated synthetic DTC and DTS curves can be generated from mineralogy and effective porosity data. These calibrated models can be used on future wells in which the operator may not have actual sonic data but still needs an accurate mechanical properties prediction. The prediction of mechanical properties from mineralogy data also allows the calibration of a “mineral brittleness” to the conventional “pseudobrittleness.” This allows mineralogy from advanced cuttings analysis techniques or neutron-induced spectroscopy logs to be used for mechanical proxy measurements.

3D Stress and Stress Orientation

Laminated clay-rich shales often exhibit large differences between vertical and horizontal elastic properties. This anisotropy is quantified in a 3D stress analysis requiring a fast shear, slow shear, and Stoneley shear from an oriented x-y dipole sonic tool. The computed 3D closure stress is a much better predictor of true fracture geometry when used in current and future 3D fracture modeling software. The orientation of the fast shear azimuth will always be in the direction of maximum principal stress, which is orthogonal to the optimum horizontal well direction.

Permeability

This software uses a linear regression technique to match core-measured GRI matrix shale permeability. This can be several orders of magnitude less than permeability estimated from a DFIT analysis but is often used as a shale quality indicator. The DFIT effective permeability can be used to calibrate Timur or Coates model system matched permeabilities, or one of two new regression permeabilities with better dynamic range. Fracture simulators require an estimate of fluid leakoff that uses such permeabilty estimates.

Pay Analysis

The software allows the analyst and asset team up to six criteria for flagging and counting net pay. Typical criteria used include effective porosity, effective water saturation, pseudobrittleness, and closure stress. Either gas or oil, or both, can be volumetrically solved and cumulative reserves are output alongside flagged net pay. If core canister isotherm data is supplied, free vs. sorbed gas volumes are also calculated in this module.

The ShaleXpert tool is then used to develop a final composite analysis (Fig. 1) that brings together all the different workflow modules in a display that aids in primary sweet-spot identification, shows in-place reserve estimates, and delivers everything required for an optimized fracture stimulation design. In this process, it can also generate individual quality-control plots and logs from any of its workflow components, so all processes are transparent to the end user.

Traceable Proppant Eliminates Need For Radioactive Detection Material

Fredy Torres and Wildiman Reinoso, Gran Tierra; Mark Chapman and Xiaogang Han, CARBO Ceramics; and Pablo Campo, Halliburton

A new ceramic proppant has made detection possible without placing radioactive material downhole. The new detection method makes use of a high thermal neutron capture compound (HTNCC) incorporated into the ceramic proppant.

Traditional fracture-height or proppant-placement evaluation after hydraulic fracturing relies on the detection of radioactive tracers pumped downhole with the proppant. Although this technique is useful, it raises environmental, safety, and regulatory issues.

The HTNCC is added to the proppant during its manufacture and is included in concentrations low enough not to affect the proppant’s strength or conductivity. The proppant is detected using standard compensated or pulsed neutron tools, with detection based on the high thermal neutron capture of the compound relative to the surrounding downhole constituents.

This new detectable proppant was used in the T sand of the Villeta and Caballos formations of the Juanambú field in the Putumayo Basin of Colombia.

Two detection methods use a comparison of before-fracture log count rates and after-fracture count rates, with reduced after-fracture count rates observed in zones containing proppant. Another detection method, especially useful when formation gas saturations change, uses only the after-fracture log.

The HTNCC method has advantages over the common radioactive particle method. First, the HTNCC tagging material is incorporated in very small quantities into each proppant grain during the manufacturing process. Because it is present in every particle of the fracture treatment, the detection of all propped fractures is insured. With traditional radioactive tracers, which are blended into the slurry at extremely small ratios compared with total proppant volume, segregation can occur, which can lead to misinterpretation of fractures in which no radioactive particles are contained near the wellbore in the propped fracture section. A related but opposite problem also can occur in situations in which a stray radioactive particle is located in an area that is not a propped fracture (e.g., a casing collar or perforation). These false positives are eliminated by the new method because the small quantities of HTNCC in a few stray pellets will not create a log response.

A second advantage, and more important in many cases, is that the new method contains only inert materials, thereby eliminating the need for the special requirements or permitting necessary for handling, transporting, pumping, or flowing back of hazardous materials associated with traditional radioactive tracers. This new method provides intrinsic value to operators by providing an environmentally friendly and virtually hazard-free alternative to radioactive tracers.

A third advantage is that the HTNCC is inherently stable and permanently incorporated within the proppant. The HTNCC can be logged at any time in the future to evaluate remedial operations or determine whether proppant has flowed back from any interval. Typical radioactive tracers experience radioactive decay, and the detectability declines as a function of the isotope half-life, which prevents the accurate identification of proppant location after a few months.

Detection Methods

Three methods for detecting the tagged proppant have been developed. Two of the methods require before-fracture and after-fracture logs, and the third requires only an after-fracture compensated neutron log. As in most cases, the Putumayo Basin field application uses only one method for the determination of proppant location. However, in some cases, multiple methods may be employed when logs are available, regardless of changes in borehole conditions or formation hydrogen index (HI) values between the before-fracture and after-fracture logs. The use of multiple methods increases the consistency of the results, and the independent validation increases the degree of certainty in the proppant location interpretation.

The first of the two methods requiring both before- and after-fracture logs requires a conventional neutron log, preferably from a compensated neutron tool (CNT), with a continuous neutron source and one or more thermal neutron detectors (or with capture gamma ray sensing detectors). Before the fracture treatment, this tool needs to log the interval of the wellbore that includes depths spanning the zones intended to be fractured, with both the detector count rates and count rate ratios recorded for use in the final analysis. The wellbore is logged a second time after fracture treatment across the same wellbore interval. The observed after-fracture count rates are then compared with corresponding values recorded in the logging run made before the well is fractured. Intervals in which after-fracture count rates are suppressed to a lower level than the before-fracture count rates identifies the presence of proppant containing HTNCC and indicates the location of the created propped fracture.

The second method that requires both before- and after-fracture logging uses a pulsed neutron capture (PNC) logging tool to detect the presence of proppant with HTNCC in the fracture. Decay curve count rate data from capture gamma ray or thermal neutron sensors, and possibly spectral gamma ray data as well, are recorded before and after the fracture treatment. The after-fracture data is compared with the before-fracture data with the formation and borehole thermal neutron absorption cross sections calculated from the PNC decay curves. Increases in the formation and borehole cross sections in the after-fracture PNC logs relative to the before-fracture logs, as well as decreases between the logs in the observed formation or borehole decay component count rates, are used to identify the presence of the tagged proppant in the induced fractures or in the borehole region adjacent to the fractured zones.

The third method available with this new proppant detection technology uses only the after-fracture compensated neutron logging for proppant location. In this method, ratios of the count rates of the near detector to the far detector (N/F) are used in the log interpretation process to create a synthetic before-fracture log for comparison. This method is useful when changes occur in the formation HI, particularly formation gas saturation changes in the zones, between the before-fracture and after-fracture logging. Gas saturation changes occur regardless of the presence of proppant. When HTNCC-tagged proppant is present in formation fractures or in the borehole region adjacent to the fractures, approximately the same percentage decrease in the count rates is observed in both detectors (N/F ratio is independent of the presence of the HTNCC proppant). However, the N/F is sensitive to changes such as nonproppant-related variations in formation porosity and gas saturation. If wellbore conditions are uniform, logged intervals known not to contain the HTNCC proppant can be used to develop a unique relationship between near detector count rate and N/F (and similarly between far detector count rate and N/F). Using these relationships, N/F can be used to compute near and far detector count rates across the entire logged interval, effectively creating a before-fracture log. These computed count rates are independent of the presence of the proppant and can be compared with the actual observed after-fracture count rates, which are sensitive to the presence of the proppant. The computed count rates will be greater than the observed count rates in intervals containing HTNCC proppant.

Case History in the Putumayo Basin

The Juanambú field is located in the extreme southwest corner of Colombia in the Putumayo Basin (Fig. 1). This basin is part of the large foreland basin referred to as Putumayo-Oriente-Marañon basin. This basin covers 320,000 km2 in Colombia (Putumayo), Ecuador (Oriente), and Peru (Marañon).

The majority of oil in this basin is found in structural traps within the Cretaceous Caballos formation and in the T sand of the Villeta formation. Other productive sands exist in the Villeta formation (Kg and Lower U), but, in the Juanambú field, they are considered secondary objectives. The Juanambú field is a trapped, fault-bounded closure formed by late Tertiary compressional forces (late Andean) that reactivated older basement source faults. This orogenic phase also buried the Cretaceous source rocks to sufficient depth to allow the generation of hydrocarbons.

Despite the good petrophysical properties measured in the productive reservoirs, the production history of Juanambú and offset wells shows reduced production because of fines migration. For this reason, the skin bypass fracturing job is designed and executed as a standard practice in the productive sands to bypass the region damaged during drilling and completion and thereby regain productivity.

After 20 hydraulic fracture jobs in the offset wells, matching the geometry with net pressure values recorded during minifrac and main treatment stages has been difficult. One of the more critical points to control is the fracture height because contacting deeper water-bearing zones is possible, which would cause water-cut increases in producer wells. To improve fracture design, geomechanical studies have been conducted that include core routines, dipole sonic logs, image logs, and electrical logs. Taking into account all these data and the new technology developed to assess stimulation jobs, the Juanambú-2 well was proposed to be a pilot project for proppant tagged with HTNCC to determine fracture height. Radioactive tracers were considered but were not used because of environmental and safety risks.

Work Description

Engineers determined that skin bypass fracturing treatments in the Caballos and the T sand formations would increase the recovery of reserves.

A baseline, before-fracture CNT that could be compared with an after-fracture CNT for determination of proppant location was run. Taking into account offset well experience, the target intervals were reperforated using a new technology that reduces the near-wellbore friction. Before the injectivity test, a pad acid was pumped to remove the formation damage generated by fines migrations and
scale precipitation.

For both stimulations, two diagnostic pumping stages were performed to collect information to match fracture parameters in the simulator. The first stage was a step-down test (SDT) used to calculate the entry hole and near-wellbore friction losses. In this specific case, a 35 lbm/1,000 gal linear gel was injected at 20 bbl/min.

Minifrac or calibration tests were designed to calculate fracturing fluid leak-off coefficient, fracturing fluid efficiency, fracture closure pressure, closure time, and fracture geometry (height, width, and length). These parameters (obtained by G-function analyses) are used to alter the subsequent fracture treatment to prevent premature screenout.

The fracture treatment designs reflect the results of the minifrac analysis. All stimulations have a 35 lbm/1,000 gal borate crosslinked fluid and 16/20 lightweight ceramic tagged with HTNCC.

Fracture Height Definition

Propped fractures containing HTNCC-tagged proppant cause a suppression of neutron counts when compared with before-fracture neutron logs. Figs. 2 and 3 show the interpretation of neutron counts (after and before) for T sand and Caballos formation.

The log interpretation indicated a fracture contained between the top (9,105 ft) and bottom (9,170 ft) shales in the T sand with the high suppression of neutrons located mainly near the perforations and representing high proppant concentration into the productive intervals extending from 9,120 to 9,169 ft. For the Caballos formation, a propped fracture was identified between 9,250 ft and 9,325 ft, with the highest concentration occurring near the perforations between 9,264 ft and 9,304 ft. In both cases, it was concluded that the border of the fracture was broken rock but that it had not retained conductivity because the fracture width was insufficient to receive HTNCC proppant to create a conductive pathway.

The observed pressure data from the bottomhole sensor was used to match the net pressure for fracture model calibration of the T sand and Caballos hydraulic fractures.

A summary of the fracture height results from both the pressure matching of the model and neutron logging of HTNCC proppant is located in Table 1. In the T sand, both methods produce a similar total fracture height and total propped height. While not drastic, results had greater variability in the Caballos, where the model pressure matching method produced a total fracture height of 30 ft greater than the HTNCC method.

Fracture Job Performance

After fracturing operations, selective production tests and transient pressure analyses were performed to assess reservoir performance.

The analyses showed that after stimulation in T sand, the skin factor changed from 20 to 0.5, representing a productivity regain of 3.25. It is important to note that the water cut measured after fracturing was 30% because the fracture dimensions reached the water leg zone in the reservoir. In the Caballos formation, the skin factor dropped from 137 to 5, representing a productivity regain of 8.6. The water cut measured after fracturing increased from 13% to 62% because the fracture height (as measured with the HTCC proppant) contacted the lower intervals (9,320–9,350 ft), which were previously producing water.

The production history before stimulation indicates this well showed a high decline rate (total fluid rate) because of fines migration and scale precipitation. After stimulation, the well has maintained a stable total production rate. Despite the water-cut increment, the net oil production increased from 385 to 625 BOPD. It is anticipated that initial drawdown conditions (50%) will be pursued; however, the current drawdown condition is maintained at 30% to assess the water-cut trends at consistent drawdown.

These results indicate that the fines migration problem was overcome with a highly permeable pathway created between the wellbore and the nondamaged reservoir zone. This highly permeable proppant pack reduces flow velocity in the matrix by creating a very large connection between the reservoir and wellbore. The proppant pack made up of large diameter, uniformly sized lightweight ceramic proppant allows small particles to more easily travel through the pore throats, thereby avoiding any blocking or fines plugging.