One of the major problems in drilling industry that increases non-productive time, expenditures and environmental damages is Lost Circulation problem of drilling fluids. Lost Circulation in formations in low pressure or unconsolidated formations can be prevented with applying appropriate wellbore strengthening materials (WSM) which mitigate formation damages and provide with having a high production index after drilling operation. In this paper, designing of wellbore strengthening materials with different mechanisms are discussed and investigated.
Considering comprehensive study on different bridging mechanisms, resilient/deformable materials, organic fibers, and also investigation on optimizing particle size distribution of WSMs, two engineered solutions were designed and evaluated using Loss Circulation Material (LCM) Tester Equipment which has a cylinder structure, also pressure valve is set up on the upper cap and a tailor-made sand bed or slotted disk is fitted on its bottom. Different type of oil-based and water-based drilling fluids with and without designed WSMs were poured into the LCM Tester equipment, then 650-psi pressure was applied for 30 minutes. For each fluid, the invasion depth and invasion rate of the fluid into the sand bed was reported, also rheological properties and API Fluid loss were measured.
According to the results, invasion depth and invasion rate of fluids containing designed WSMs is magnificently lower in comparison with drilling fluids which not contained any WSMs. Drilling fluids contained the designed WSMs are highly-effective in both reservoir and non-reservoir formations for stabilizing the wellbore and preventing seepage loss in sandstones and mini-fractured formations. Evaluation of rheological properties and API-Fluid loss (before and after hot-rolling in 250° Fahrenheit for 2 hours) and comparing them with blank samples confirmed that designed WSMs did not have major adverse effect on rheological and fluid loss parameters. Designed WSMs in this paper can hold pressures as high as 650 psi in LCM tester equipment on (sand bed with permeability up to 5 Darcies) or slotted filter disks (up to 200-micron fracture width). Last but not least, regarding wellbore strengthening mechanisms, one of the WSMs includes dual bridging mechanisms in sandstone formations and the latter includes forming a stress cage in the wellbore surface that causes to decreasing permeability of the formations while drilling due to expansion of its designed resilient materials in the fractures.
Main goal of this research is using environmentally-friendly and economic waste materials to design highly effective WSMs. One of the designed WSMs includes environmentally-friendly organic waste fibers as a higher concentration additive. Additionally, one of the designed WSMs is more than 80% acid-soluble in 15% hydrochloric acid and the other one will be detached and left the wellbore pore-throats with beginning of production without any damage to reservoir zones.
Formation pressure and sampling measurements in low mobility formations under dynamic filtration can lead to measurements influenced by continuous mud circulation. Generally, active mud circulation inhibits mud cake growth, promoting filtration and invasion of mud filtrate into the reservoir. The resulting invasion adds its own pressure to the actual formation pressure. This is more pronounced in low mobility formations where pressure or sampling measurements made with mud circulation show higher than expected reservoir pressures and/or extended clean up times as a result of dynamic filtration and invasion.
We focus on formation pressure acquisition and present data sets where pressure acquisition was done with active mud circulation. The data is then compared with measurements acquired in a pseudo-static and static mud column.
The measured near wellbore formation pressures acquired with active mud filtration are significantly higher (in some cases, > 400psi) compared to those obtained with a static mud column (assumed to be reading closer to the true formation pressure). The additional pressure is often referred to as supercharging, i.e., the excess pressure superimposed on the original formation pressure by the viscous flow of mud filtrate. The difference depends amongst other factors primarily on the formation mobility and surface pump flow rate during the pressure acquisition. For higher mobilities, there is generally little appreciable difference between active mud circulation and zero mud circulation. Secondary factors like pipe movement, pipe diameter, mud composition and reservoir wettability also influence the degree of the extra pressure measured.
Best practices for formation testing while drilling in low mobility carbonates are discussed. Lessons are drawn from experience where ignoring such best practices result in questionable data.
Pre-loading parent wells with surfactant-based treatment fluids for frac hit mitigation has been applied extensively in liquids-rich shale plays, where infill drilling and tighter well spacing are prerequisites for improved production and economic return. Pre-loads can provide a significant and temporary increase in fracture network pressure if done properly and are most effective with a surfactant and solvent package. However, it remains elusive why specific chemical packages help improve the parent well production, although the notion of capillary force resistance reduction for further treatment fluid leakoff into fractures and rock wettability alteration by surfactant has been proposed previously. Recent residual surfactant analysis in produced water from both parent and child wells indicates that there is indeed hydraulic communication after frac hits, and field trials in the Wolfcamp suggest that adding the same surfactant package in primary frac fluids in child wells can migrate to parent wells, thereby potentially activating various secondary oil recovery mechanisms.
Astrategy for properly selecting a surfactant solvent package is presented for parent wells. Most conventional surfactant tests do not provide much insight in the absence of formation rock. Instead, a rock-on-a-chip microfluidic device is used to illustrate the interactions between parent and child wells when frac hits occur. Spontaneous imbibitions of primary frac and secondary treatment fluids into formation rocks are performed along with computed tomography (CT) imaging to understand the surfactant efficacy for enhancing leakoff into secondary fractures.
Oil recovery and associated water saturation in the microfluidic-based device with or without surfactant are quantified and reveal that the oil recovery is enhanced with surfactant, and water saturation in the parent well could be reduced thereby mitigating water blocks from primary frac fluid invasion from child wells. Spontaneous imbibition results provide insight into a surfactant's effectiveness to leakoff into secondary fractures within a matter of several days, which coincides with a typical short time window for the offset frac to begin to achieve maximum pressure support.
Borehole measurements are often subject to uncertainty resulting from the effects of mud-filtrate invasion. Accurate interpretation of these measurements relies on properly understanding and incorporating mud-filtrate invasion effects in the calculation of petrophysical properties. Although attempts to experimentally investigate mud-filtrate invasion and mudcake deposition have been numerous, the majority of published laboratory data are from experiments performed using linear rather than radial geometry, homogeneous rock properties, and water-based (WBM) rather than oil- or synthetic oil-based drilling mud (OBM or SOBM).
We introduce a new experimental method to accurately reproduce conditions in the borehole and near-wellbore region during, and shortly after the drilling process, when the majority of wellbore measurements are acquired. Rather than using a linear-flow apparatus, the experiments are performed using cylindrical rock cores with a hole drilled axially through the center. Radial mud-filtrate invasion takes place while injecting pressurized drilling mud into the hole at the center of the core while the outside of the core is maintained at a lower pressure. During the experiments, the core sample is rapidly and repeatedly scanned using high-resolution X-ray microcomputed tomography (micro-CT), allowing for visualization and quantification of the time-space distribution of mud filtrate and mudcake thickness. Because of the size of the core sample, the developed experimental method allows for accurate evaluation of the influence of various rock properties, such as the presence of spatial heterogeneity and fluid properties, including WBM versus OBM, on the processes of mud-filtrate invasion and mudcake deposition. Results indicate that our experimental procedure reliably captures the interplay between the spatial distributions of fluid properties and rock heterogeneities during the process of mud-filtrate invasion.
Golovko, Julia (Halliburton) | Jones, Christopher (Halliburton) | Dai, Bin (Halliburton) | Pelletier, Michael (Halliburton) | Gascooke, Darren (Halliburton) | Olapade, Peter (Halliburton) | Van Zuilekom, Anthony (Halliburton)
Phase behavior characterization (PVT) and geochemical compositional analysis of petroleum samples play a crucial role in the reservoir evaluation process to help determine producible reserves and the best production strategy. Openhole samples are the most valuable types of samples for PVT and geochemical analysis. Unfortunately, traditional openhole sampling methods are costly and limited to ten to twenty samples, thereby restricting the scope of characterization in a well section. This study summarizes a new microsampling technique for logging while drilling (LWD) and a corresponding wellsite technique to provide compositional interpretation, contamination assessment, reservoir fluid compositional grading, and reservoir compartmentalization assessment. This microscale approach allows fast analysis with a field or near-field deployment of the analytical tool, providing fast turnaround time for analysis. The results inform planning for wireline sample retrieval, if necessary.
The microsampler used in the downhole tool is capable of collecting reservoir fluid in small quantities, suitable for compositional analysis. Because of its small size, the microsampler can gather multiple fluids at various reservoir depths, while PVT sampling requires larger volumes and has more constraints. However, when used in combination with conventional PVT-grade samples, the microsamples can provide significant chemical profiling. The quantity of 40 microliters (
Recovery to surface of fluid samples collected at reservoir temperature and pressure allows for analysis with an automated gas chromatograph (GC) deployed in the field, providing reduced labor and rapid analysis. The unique injection chamber of the GC is designed with the injection port and valve configured to withstand pressure up to 5,000 psi, which is approximately five times higher than standard GC injection valves. This allows for injection of the microsample with a solvent carrier as a single-phase fluid so that analysis can provide composition and fluid properties, such as gas to oil ratio, without a flash. The GC has two detectors including a flame ionization detector (FID) for hydrocarbon components and thermal conductivity detector (TCD) for inorganic gas components, such as carbon dioxide, nitrogen, and hydrogen sulfide. The system can quantify hydrocarbon components from C1-C36 and perform contamination studies of oil samples with drilling fluids.
This study provides a new technique for reservoir engineers to characterize a reservoir completely, without limit to the number of acquired samples. In combination with conventional PVT samples, it is possible to extrapolate the PVT properties to all pump-out stations, and conduct a complete geochemical profile of the reservoir.
Successful in-situ fluid cleanup and sampling operations are commonly driven by a fast and reliable analysis of pressure, rate, and contamination measurements. Currently, techniques such as pressure transient analysis (PTA) and rate transient analysis (RTA) provide important information to quantify reservoir complexity, whereas fluid contamination measurements are overlooked for reservoir characterization purposes. The objective in this paper is to introduce a new interpretation technique to relate fluid contamination measurements with reservoir properties by identifying early- and late-time flow regimes in the derivative plots of reciprocal fluid contamination. Among several applications, this new transient analysis method is effective for improving logging-while-drilling (LWD) fluid sampling operations.
The derivative methods used in PTA and RTA inspired the development of the new fluid contamination interpretation method. Contamination transient analysis (CTA) evaluates transient measurements acquired during mud-filtrate invasion cleanup to infer reservoir geometry. We apply derivative methods to the reciprocal of the time evolution of fluid contamination to identify flow regimes in cases of water-based mud invading either water-or hydrocarbon-saturated formations. LWD operations are considered under a continuous invasion effect, i.e. the fluid cleanup procedure is performed while mud filtrate continues to invade the formation. This constraint brings about a significant technical challenge for LWD fluid sampling jobs. Alternatively, this new method could be integrated with other pressure transient techniques to improve the interpretation of measurements. For example, in a pretest case where the pressure transient does not achieve the radial flow regime, fluid cleanup could provide complementary information about late-time flow regimes to enhance the acquisition of measurements in real time.
We document synthetic and field examples of applications of a new interpretation method. Seven reservoir cases are simulated to obtain contamination data: (1) homogeneous isotropic reservoir, (2) formation thickness, (3) laminated formations, (4) geological faults, (5) mud-filtrate invasion (6) reservoir properties, and (7) permeability anisotropy. All these cases are compared for single-phase and multiphase flow during LWD fluid sampling operations. Additionally, field case studies are analyzed to highlight the value of the reciprocal contamination derivative (RCD) in real-time operations. Reservoir limits and features such as saturating fluid and depth of invasion are identified in the flow regimes detected with derivative plots of the reciprocal of the contamination. Consequently, LWD cleanup and sampling efficiency could be optimized based on contamination transient analysis by identifying the flow regimes taking place in the reservoir during filtrate cleanup, hence improving the prediction of the time required to acquire non-contaminated fluid samples.
The new approach of the reciprocal contamination derivative is an alternative way to optimize fluid cleanup efficiency and to quantify the spatial complexity of the reservoir during real-time LWD operations. In addition, this new technique enables the evaluation of reservoir properties in less operational time than PTA without the need of pressure build-up stages, increasing fluid sampling efficiency in terms of quality and time.
In some complex reservoirs, low-resistivity/low-contrast pay, low-porosity/low-permeability, and medium-to-heavy oil, nuclear magnetic resonance (NMR) log data--independently or in combination with other log data--provide the best and/or only means of accurate formation and fluid evaluation. Because NMR-log data acquisition is complex, job preplanning is essential to ensure optimal selection of acquisition parameters that will result in reliable and accurate data and in the maximum information possible in any given reservoir and logging environment. A clear understanding of the logging job objectives is necessary for optimizing the NMR acquisition parameters to best achieve these objectives. This process must take place before the actual logging. In addition to job objectives, determination of the appropriate NMR-acquisition parameters is also influenced by operational considerations and the anticipated in-situ reservoir properties (Fig.1).
To estimate Rt under a variety of different logging conditions and in different formations, a simple three-parameter, step-profile invasion model is often used. This model consists of a flushed zone of resistivity Rxo and a sharp boundary at diameter di, with the uninvaded zone of resistivity Rt. Three independent, borehole-corrected resistivity measurements with appropriately chosen depths of investigation contain enough information from the formation to reliably solve for Rt using this model. Measurements with the following features should be chosen: small, correctable borehole effects; similar vertical resolutions; and well-distributed radial depths of investigation--one reading as deep as practical, one very shallow reading, and one intermediate reading. In conductive muds, the Dual Laterolog (DLL) Resistivity– Rxo combination tool provides simultaneous measurements suitable for evaluating Rt, Rxo, and di. It should be said that the value of Rt in a given bed is an interpreted parameter, and is almost never measured.
Nuclear log interpretation is simply the practice of solving tool-response mixing-law equations with the judicious application of some assumptions and constraints. As more factors are taken into account, the interpretation usually improves, but the model becomes more complicated. For the neutron-porosity log, the simplest interpretation model is to naively accept the raw log reading. If the reservoir is shaly, or if the fluid density is not the same as water, a hydrogen-index linear-mixing law will generally do. This equation can be solved for ϕe given the neutron-tool response to each of the various formation components.