Results from a long-term field study to improve zonal isolation show that rotating production casing in unconventional well laterals is possible and that it delivers excellent cement quality. This paper reports the results of the study. To date, 44 production strings have been rotated during cement jobs. Specific details covered are cement bond evaluation results, methods used for modeling casing running, torque and drag forces for floated and rotated strings, torque estimation for casing connection selection, operational procedures, mud conversion cement additive, and best practices. Evaluation of cement bond is based on ultrasonic cement logs acquired in casing strings cemented with and without casing rotation. Advanced azimuthal ultrasonic logs were used to measure cement placement and quality. Trials with a mud conversion cement additive evaluated whether the cement quality could be achieved with additives instead of rotation. Both 6¾ in. and 8½ in. hole sizes in 10,000 ft lateral lengths were evaluated. Prior studies demonstrated that casing movement is crucial for efficient mud removal ( Hyatt et al. 1984 ; Gai et al. 1996 ), yet it is not a common practice on long horizontal sections in our company. The casing rotation initiative reported here was enabled by the availability of reliable high torque casing connections. The results shared in this paper demonstrate that it is necessary to rotate casing while cementing horizontal wells with 10,000 ft lateral lengths for effective cement isolation in the annulus. The cement bond resulting from rotated cement jobs is near-perfect. Long-term study is needed to evaluate the effect of optimal cement on hydraulic fracturing effectiveness, production, and the long-term health of the well. Results reported include log data and modeled torque and drag values paired with operational data to validate the models. Log data is available for eight lateral wellbores evaluated during the base case and trial period. It is unique in that log data was acquired for both the base case and trial wells. This paper supports well-known cementing best practices ( McLean et al. 1967 ; Zurdo et al. 1986 ; Reiley 1987 ; Wilson et al. 1988 ; Sabins 1990 ; Torsvoll et al. 1991 ; Kettl 1993 ; McPherson 2000 ; Nelson et al. 2006 ; Al-Baiyat et al. 2019 ) with undisputable log data. The operational practices can be applied to many unconventional operations to implement casing rotating into their cementing programs. The method shared to estimate torque can be implemented by any drilling engineer with access to torque and drag software, enabling them to choose the right casing connection for their application.

Faster production declines than initially forecast were observed in numerous deep-water assets. These wells were completed as Cased Hole Frac-Pack (CHFP) completions ( Knobles et al. 2017 ) with the assumption that rock failure although not initially expected would occur at some point during the production life of the well. This work indicates that failure of the rock and proppant are significant factors impacting Productivity Index (PI) Decline. The paper delves into each of the identified mechanisms and how they impair well productivity. Seven key damage mechanisms were identified as forming the basis for PI degradation: 1) off-plane perforation stability, 2) fines migration, 3) fracture conductivity, 4) fracture connectivity, 5) fluid invasion, 6) non-Darcy flow and 7) creep effects. A near wellbore production model incorporating the completion, fracture geometry and reservoir is coupled with a geomechanics model to assess each mechanism. A Design of Experiment setup varies the input ranges associated with each of the seven damage mechanisms. Input parameters for the model are risked and rely on ranges from standard and newly developed well and lab tests. The model assesses well performance and driving mechanisms at different points in time within the production life. Primarily the study focused on high permeability and highly over pressured reservoirs. For the types of wells/fields assessed in the study, the results indicated three phases of decline based on the interaction between the formation properties, the completion components and the operating parameters. The three phases breakdown into: (1) a pre-rock failure stage where declines are relatively small, (2) an ongoing rock failure stage where declines are rapid and (3) a post failure stage where declines are again moderate. In each of these stages different parameters and damage mechanisms were assessed to be impactful. The workflow was also utilized to match pre and post acidizing treatments. A comparison for varying rock types was included looking at the impact of rock strength and formation permeability on the ranking of the damage mechanisms. The impact of operating parameters such as drawdown can also be assessed with the tool showing that increased drawdowns may not always be beneficial to the long-term production of the well. The paper presents the underlying drivers for PI Decline for deep-water assets of a specific attribute set. Through accurate representation of reservoir and completion, the workflow highlights the impact and combined impact of different damage mechanisms. The paper also shows a direct link between the mechanical properties (moduli and strength) and boundary conditions (pore pressure and stress) and the well performance and productivity. The workflow provides a methodology by which lab and field tests can be transformed into assessments of future well performance without strictly relying on analogs that may or may not be appropriate.

Severe drilling dynamics of a bottomhole assembly (BHA) causes energy to dissipate into vibrations which undermines drilling efficiency. Dangerous dynamics modes, such as backward whirling and high frequency torsional oscillation, could cause downhole drilling tools to fail prematurely. To mitigate the risk of failure due to these dangerous conditions, it is critical to identify the damaging dynamics modes by interpreting the drilling data. Based on a deep learning approach, a novel method was proposed to automatically identify severe drilling dynamics modes directly from the time-series data. The drilling dynamics data can be obtained from either a downhole sensor measurement or transient dynamics simulation. First, a deep neural network, which is composed of convolutional and fully connected layers, is employed to explore patterns in the data by generating a feature map of drilling dynamics. Knowledge of drilling dynamics physics can be used to facilitate data clustering in the feature map. Each data cluster can be tagged with the corresponding drilling dynamics mode. Using the tagged dataset, a machine learning classification model can be trained to automatically identify the dynamics modes based on the input of time-series drilling data. The deep learning approach can be implemented to recognize a collection of dynamics modes of BHA, such as various whirling patterns and high frequency torsional resonance. The most commonly available drilling dynamics data channels, accelerations and collar RPM, were used as the model inputs. The deep neural network was trained to predict the next data sample based on the previous time-series data. One of the hidden layers of the neural network was employed to generate the feature map, in which the dataset forms several clusters. The orbits of BHA movement were plotted on top of the clusters for pattern visualization. After this practice, the simple polygon boundary was drawn between whirling and stable cases, and the dataset was tagged automatically. With the tagged dataset, the classification model was trained to identify various whirling patterns and the stable drilling state. Similar processes can be readily applied to interpret other dynamics modes. Interpreting the drilling dynamics modes provided a high-level description of the data, which offered clues on how to optimize BHA design and drilling practices to improve efficiency. The automatic interpretation of drilling dynamics data can significantly improve the consistency and efficiency of the existing manual interpretation workflow. The generated feature map enables the exploration of new motion patterns and new vibration modes. This approach eliminates the need to manually tag the data. With minimum human interactions, the dataset can be automatically tagged. The model employs only the raw time series data of basic dynamics channels as inputs, which makes the algorithm universally applicable for various data sources.

In the last decade, technical advancements have greatly improved the design and execution efficiency of well completions, leading to improved recovery from unconventional reservoirs. However, analyzing fracture diagnostic tests in unconventional plays are still challenging due to high uncertainty in predictive capabilities in the context of fracture dynamics during treatment. The main objective of this study is to identify fracture behavior during injection and pressure fall-off periods in hydraulic fracturing treatments and diagnostic fracture injection tests (DFIT), respectively. In this study, discrete wavelet transformation (DWT) was used to analyze real field injection and fall-off data in the wavelet domain. The analyzed data are from multi-stage hydraulic fracturing operations and DFIT in unconventional horizontal wells. DWT coefficients reveal very crucial information related to the nature of the events within recorded signals; they also reveal various patterns that are hard to recognize otherwise. The high-frequency components of the pressure and rate signals (detail coefficients) that are calculated by the wavelet transformation determine localization and separation of various events. We compared the identified events for injection and fall-off periods with moving reference point (MRP) and G-function analysis, respectively. The main advantage of our proposed approach is that it is based on real-time data and does not require any assumptions related to existing or created fractures. Also, it is very sensitive to physical changes in the system; thus, it reveals hidden information related to those changes. Consequently, the energy of detail coefficients represents several events at different frequencies. We used pseudo-frequency of wavelet coefficients as a diagnostic tool for an accurate comparison of fracture propagation and fracture closure events to determine similarities and differences between them. For example, the signal energy of detail coefficients from the wavelet transformation of hydraulic fracturing data demonstrates abrupt frequency changes during dilation or fracture height growth during fracture propagation. Therefore, we were able to identify those events by energy density analysis in both time and pseudo-frequency domains in an objective manner, which otherwise was not possible with conventional methodologies such as G- function derivative analysis. This paper details the successful methodology for effective implementation of a new fracture diagnostic technique for fracturing operations or DFITs in unconventional horizontal wells. This new fracture diagnostic method does not require any reservoir or fracture pre-assumptions; it mainly relies on the pressure behavior, which is a result of various events at different frequencies. Pressure fall-off behavior of a DFIT gives essential information related to closure event of the created mini-fracture. Identification of these events at different pseudo-frequency ranges improves the understanding of the dynamic fracture behavior also the characteristics of the reservoir. Unlike many other diagnostic techniques, this data-driven approach requires minimum input/data for analysis. This approach also lends itself to real-time application quite easily.

Reliability of subsurface assessment for different field development scenarios depends on how effective the uncertainty in production forecast is quantified. Currently there is a body of work in the literature on different methods to quantify the uncertainty in production forecast. The objective of this paper is to revisit and compare these probabilistic uncertainty quantification techniques through their applications to assisted history matching of a deep-water offshore waterflood field. The paper will address the benefits, limitations, and the best criteria for applicability of each technique. Three probabilistic history matching techniques commonly practiced in the industry are discussed. These are Design-of-Experiment (DoE) with rejection sampling from proxy, Ensemble Smoother (ES) and Genetic Algorithm (GA). The model used for this study is an offshore waterflood field in Gulf-of-Mexico. Posterior distributions of global subsurface uncertainties (e.g. regional pore volume and oil-water contact) were estimated using each technique conditioned to the injection and production data. The three probabilistic history matching techniques were applied to a deep-water field with 13 years of production history. The first 8 years of production data was used for the history matching and estimate of the posterior distribution of uncertainty in geologic parameters. While the convergence behavior and shape of the posterior distributions were different, consistent posterior means were obtained from Bayesian workflows such as DoE or ES. In contrast, the application of GA showed differences in posterior distribution of geological uncertainty parameters, especially those that had small sensitivity to the production data. We then conducted production forecast by including infill wells and evaluated the production performance using sample means of posterior geologic uncertainty parameters. The robustness of the solution was examined by performing history matching multiple times using different initial sample points (e.g. random seed). This confirmed that heuristic optimization techniques such as GA were unstable since parameter setup for the optimizer had a large impact on uncertainty characterization and production performance. This study shows the guideline to obtain the stable solution from the history matching techniques used for different conditions such as number of simulation model realizations and uncertainty parameters, and number of datapoints (e.g. maturity of the reservoir development). These guidelines will greatly help the decision-making process in selection of best development options.

Operators face the continuing challenge to improve drilling efficiency for cost containment, especially in deepwater drilling environments where drilling costs are significantly higher. Innovative drilling technologies have been developed and implemented continuously to support the initiative. In many areas of the world, including the Gulf of Mexico (GOM), hydrocarbon reservoirs exist below thick non-porous and impermeable sequences of salt that are considered a perfect cap rock. However, salt poses varied levels of drilling challenges due to its unique mechanical properties. At ambient conditions, the unconfined compressive strength (UCS) of salt varies between 3,000 to 5,000 psi; however, the strain at failure for salt can be an order of magnitude higher when compared to other rocks. Consequently, during drilling salt's viscoelastic behavior requires that its must be broken with an inter-crystalline or trans-crystalline grain boundary breakage. When compared to other rock types, the unique isotropic nature of salt results in a level of strain that is much higher for the given elastic moduli. This strain level makes salt failure mechanics different from other rock types that are prevalent in the GOM. Hybrid bits combine roller-cone and polycrystalline diamond compact (PDC) cutting elements to perform a simultaneous on-bottom crushing / gouging and shearing action. Two divergent cutting mechanics pre-stresses the rock and apply high strain for deformation and displacement, resulting in highly efficient cutting mechanics. To meet the drilling objectives, different hybrid designs have been implemented to combine stability and aggressiveness for improved drilling efficiency. An operator, while drilling salt sections at record penetration rates, has successfully used this innovative process of rock failure utilizing the dual-cutting mechanics of hybrid bits. This has resulted in significant value additions for the operator. This paper analyzes field-drilling data from successful GOM wells and attempts to correlate salt failure mechanics and provide insight into dual-cutting mechanics and its correlation with salt failure. The paper also reviews the drilling mechanics of hybrid bits in salt and highlights importance of dual-cutting mechanics for achieving higher penetration rates in salt through improved drilling efficiency.

Objectives/Scope This paper uses pseudo-time to extend the application of constrained multiwell deconvolution algorithm to gas reservoirs with significant pressure depletion. Multiwell deconvolution is the extension of single well deconvolution to multiple interfering wells. Constraints are added to account for a-priori knowledge on the expected deconvolved derivative behaviors and to eliminate non-physical solutions. Methods, Procedures, Process Multiwell deconvolution converts pressure and rate histories from interfering wells into constant-rate pressure responses for each well as if it were producing alone in the reservoir. It also extracts the interference responses observed at each of the other wells due to this single well production. The deconvolved responses have the same duration as the pressure history. This allows to identify reservoir features not visible during individual build ups. Deconvolution techniques can only be applied to pressure and rate data when flow can be represented by linear equations. In strongly depleted gas reservoirs, fluid properties, and gas compressibility in particular, are pressure dependent, which makes the flow problem non-linear. The paper uses pseudo-pressure and pseudo-time transforms to linearize the problem in such conditions. Results, Observations, Conclusions The pseudo-time method developed by Levitan and Wilson (2010) is extended to constrained multiwell deconvolution in highly depleted gas reservoirs. It is an iterative process, which yields the correct initial gas in place, whereas the use of real time does not. The algorithm is validated with a two gas well synthetic example, and successfully applied to a field case with four gas producers. Novel/Additive Information The paper extends the application of constrained multiwell deconvolution to strongly depleted gas reservoirs. Constrained multiwell deconvolution is an efficient way to exploit data recorded by permanent downhole pressure gauges and provides information not otherwise available. It can help to identify field heterogeneities and compartmentalization early in field life, making it possible to modify the field development plan and to improve locations of future wells. It can accelerate history-matching with the reservoir model by doing it on the constant rate pressure responses rather than on the actual, usually complex, production history. An added advantage is that comparison between the pressure derivatives of the model and the actual deconvolved derivatives allows identification of mismatch causes.

Geostatistical-based models provide a considerable improvement for predictive reliability of dynamic models and the following reservoir management decisions. This study focuses on geostatistical modeling the Paleocene Zelten Carbonate reservoir in the Meghil field. The field was discovered in 1959 and production operations began in 1961. Nineteen wells have been drilled to date. The structural framework consists of three slightly asymmetrical anticlinal structures trending NW-SE with steeper dip on the SW flanks. Each of the structures are separated by major normal faults. Seismic interpretation suggests that carbonate build-ups are most likely present on the three separate structures. Edge detection was used to clarify the structural geometries and the presence of additional minor faults. Pillar gridding technique was used to develop the structural framework including four major faults that are partially sealed based on analysis of the available DST and production test data. Stratigraphic analysis indicates a local presentation of dolomitic limestone in the northern portion of the main and the western structures caused considerable litho-facies variation that impacted the distribution of the petrophysical properties. Basic and advanced formation evaluation the net reservoir thickness of about 15 feet with an average porosity of 17% and average water saturation of 35%. Geostatistical-based applications that combine the spatial statistics (e.g. the semivariogram) and the available well and core data were used to populate the reservoir model with porosity, permeability, facies (lithology), net/gross, and water saturation. A conceptual facies model was also used to constrain the reservoir property distributions. Sequential Gaussian Simulation (SGS) was used to populate the model with porosity and water saturation and Sequential Indicator Simulation (SIS) was used to populate the facies model with permeability. The modeling parameters (e.g. semivariogram, correlation coefficients) were significantly constrained by the limited number of wells. Based on the limited number of wells available the semivariogram analysis resulted in a spherical semivariogram model with major axis range of 1435 meters for porosity and 1800 meters for water saturation. Minor axis ranges were about 50% of the major axis ranges. Given the limited well data, a significant effort was made to document the potential impact of the semivariogram parameters on the original hydrocarbon in place (OHIP) estimates and the lateral stratigraphic continuity of reservoir properties. The deterministic approach resulted in place volume estimates of 60 MMBBL and the stochastic approach provided an estimate of 45 MMBBL.

It is very difficult to predict the hydraulic fracture properties in shale gas reservoirs, such as Marcellus shale, because of the complex nature of hydraulic fracture growth, lack of good quality reservoir information, and very low matrix permeability. Furthermore, Marcellus shale is more sensitive to stress changes caused by hydraulic fracture shadowing and the net stress increase with production. The inclusion of the stress shadowing and the geomechanical factors provide a more realistic approach to predict the production performance of the horizontal wells with multiple hydraulic fracture stages in Marcellus Shale. The objective of this study is to investigate the impact of the stress shadowing on the hydraulic fracture properties in Marcellus Shale horizontal wells and consequently the production performance. The natural gas in the Marcellus Shale is produced most effectively by horizontal wells with multiple hydraulic fracture stages. The propagating fracture causes a stress change, commonly known as a stress shadow, in the vicinity of the fracture. The stress shadowing effects may result in a decrease in the width and conductivity of the subsequent fracture stages. In this study, a commercially available software which accounts for the stress shadowing was utilized to predict the hydraulic fracture properties based on the available information from a Marcellus Shale horizontal well. The available information included gamma ray (GR), density (RHOB), resistivity, and sonic (DTC & DTS) logs as well as the fracture stimulation treatment data. Treating pressures were calibrated by modifying the frictional parameters such as pipe friction and tortuosity factors. The predicted hydraulic fracture properties with stress shadowing effects as well as the Marcellus Shale properties were then utilized as the inputs for a reservoir simulation model in order to predict the production performance. Laboratory measurements and published studies on Marcellus shale core plugs provided the foundation for evaluating the impact of net stress on the matrix and fissure permeabilities as well as the relation between fracture conductivity and the net stress. The geomechanical factors were then incorporated in the production simulation model. Finally, parametric studies were performed to investigate the impact of fracture spacing on stress shadowing. The hydraulic fracture properties for different spacing were then incorporated in the production simulator to investigate their impact on the gas production. The inclusion of the stress shadowing and the geomechanical factors provided a closer agreement between the simulated and actual production history for the well under study. The stress shadowing effects were found to increase with closer fracture spacing. The fracture half-length, fracture height and especially, fracture width stress were impacted by stress shadowing. Additionally, it was observed that the stress shadowing impact is more significant in Marcellus shale due to low in-situ stress contrast with the adjacent zones. Furthermore, the stress shadowing effects were found to have more impact on the production than the location of the fracture stages. Finally, the stress shadowing can reduce gas recovery by as much as 20%.

Inter-well connectivity (IWC) is one of the most significant properties when evaluating the success of a waterflood. This connectivity has been obtained from various physics-based methods such as simulations, tracers and using heuristics and semi-analytical tools like capacitance-resistance model (CRM). Production and injection data are a key piece of information required to compute the IWC. In this study, we present a new method for estimating IWC using signal processing techniques on the wavelet transform of the injection and production rate data. First, the injection and production rates are subjected to multiresolution analysis using the wavelet transform to determine the detail coefficients. The variance of the detail coefficients is then computed and is ready to be processed using various signal processing techniques. Signal processing techniques such as cross-correlation, time lag, Spearman correlation, and Kendal correlation are used to identify the level of relationship between the processed injection and production data in wavelet scale space. Based on the correlation coefficients, a new IWC link parameter is proposed for characterizing the IWC between well pairs. The IWC link parameters between well pairs are then plotted for visual representation. We created several simulation models for multi-well systems, established water-flood patterns, and for randomly placed wells to establish the new IWC link parameter. The resulting injection and production rates were analyzed using the methodology above and the new IWC link parameter is established in terms of cross-correlation coefficient. We also performed several simulations for a heterogenous reservoir to compute and compare the accuracy of the new IWC link parameter. Finally, the methodology is subjected to real field waterflooding, and compared against the CRM results, which shows a good agreement. The visual representation gives new insight into whether the connectivity is being affected by the reservoir or from near wellbore events (such as changes in skin). This study integrates signal processing techniques and waterflood IWCs. Novel use of wavelet transforms coupled with variance for processing the injection and production rate data is proposed. It must be emphasized that wavelet is used in this context for processing and not for smoothing or data compression. Ultimately, this method can be implemented as a real-time automated monitoring system. Moreover, the new IWC link parameter provides insights by identifying problematic IWC, well-completion issues, and high perm channels for taking timely operational decisions.

Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. One potential weakness of multi-stage hydraulic fracturing is that the later stages of the completion workflow – frac-plug drill out (FPDO) and flowback – cause large pressure fluctuations and transient flows through the perforation clusters that coincide with a period of low closure stress in the fractures. The proppant packs in the fractures during this period are fragile and prone to failure. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs and the subsequent well performance. In this paper the results from over 200 FPDO and flowback operations from the United States and Argentina are reviewed. These results show that maintaining a balanced flowrate during FPDO operations is critical for minimizing inadvertent damage to the hydraulic fracture network. The FPDO flowrate balance is the difference between the coiled tubing injection and annular return flowrates. The magnitude and sign of the balance corresponds to the instantaneous flowrate through the open perforation clusters into or out of the hydraulic fracture network. A positive balance rate, or overbalance, injects fluid into the fracture system. A negative balance rate, or underbalance, produces stimulation or formation fluids from the fracture network. Sudden changes between these two regimes creates local flows that can be severe enough to flush large quantities of proppant out of the fractures. Our results show that high-frequency multiphase flowmeters simplify the process of maintaining balance (no inflow, no outflow). Furthermore, close monitoring of any imbalance that develops, and rapid control of the surface choke and injection rate, can provide for an efficient operation while protecting the integrity of the fracture system. Early monitoring of flowback and production with a high frequency flowmeter was shown to be extremely useful technique for optimizing well productivity during well clean-up. This paper also shows how a dual energy gamma ray multiphase flowmeter successfully quantified proppant produced during FPDO and flowback. Examples of the dynamics of sand production are shown, as well as correlations to events of excessive underbalance conditions. At the end of the paper we show that most of the highlighted problems can be solved through making changes to the well construction workflow and accounting for relationships between various well operations. Incorporation of this workflow enables early prediction of well performance issues and their efficient resolution.

DTS/DAS applications provide key advantages in surveillance and better understanding of both unconventional and thermal operations in terms of key attributes including but not limited to conformance, wellbore integrity in better spatial and temporal terms. This study investigates the effects of CO 2 in enhancing the steamflood process while incremental benefits are achieved through improved monitoring of the steamflood injection process using DTS/DAS applications using a completely synthetic but realistic reservoir model. A full-physics reservoir simulator is used to model the process. The technical and economic details of deployment of DTS/DAS as well as the steam-additive process are outlined in detail. Sensitivity study carried out on the model indicates the key attributes along with their significance. Athabasca bitumen properties are used. CO 2 additive increases the steam chamber size but lowers the steam temperature while naptha/CO 2 additives lower the viscosity, thus optimization study carried out the optimum operating levels of the additives not only in physical production/injection terms but also in terms of economics. The results indicate better reservoir management with DTS/DAS applications compared to the base case and injection can be monitored and adjusted better with such tools. DTS/DAS applications prove useful not only in terms of production performance but also in terms of economics. Physical properties of CO 2 and naptha outline that the two have different dominant modes of improving recovery with steam-only injection. CO 2 increases the extent of the steam chamber while lowering the steam temperature significantly. This study approaches the delicate process of additive use in steam processes while coupling the additional benefits of use of DTS/DAS applications in optimizing the recovery and the economics outlining the key attributes and the challenges and best practices in operations serving as a thorough reference for future applications.

Use of regional sand in the Permian Basin dramatically increased in 2018. Regional or in-basin sand is often perceived as lower quality compared to northern white sand (NWS); however, its use is fairly new, and production data has not been available to determine if, or in what cases, higher quality matters. This paper presents the results from a production comparison of Permian Basin wells that were hydraulically fractured with NWS and regional sand or both. A dataset consisting of approximately 450 wells completed with NWS or regional sand or both within the Delaware and Midland Basins was studied to determine the relationship between production performance and sand type (or quality). To evaluate the effect of sand quality in well production, the dataset was divided in smaller groups of wells with similar reservoir characteristics and completion practices. The initial phase of the study was completed using public domain production data, while the second phase focused on the development of regional reservoir models to forecast production of wells using NWS or regional sand or both. When analyzing an area containing sufficient wells for a reliable comparison, the survey revealed no statistically significant difference in production for wells that used NWS versus regionally sourced sand. Models were built to predict differences in the production performance of each sand type. These models take into account and demonstrate the effects of differences in sand properties, as well as the impact of the favorable economics associated with regional sands. It was confirmed with the study that the sand type is not a critical factor in regards to production performance when completing wells that are hydraulically fractured in ultralow-permeability nonconductivity-limited reservoirs. This paper presents an early look at the production numbers of West Texas wells completed with regionally sourced sand in the Permian Basin. The results of the study will encourage operators to further contemplate the use of regional sand when completing wells in ultralow-permeability shale reservoirs. This dataset will continue to evolve and reveal the effects of regional sand over the life of the well; this will be presented in a future paper.

PI (Productivity Index) degradation is a common issue in many oil fields. To obtain a highly reliable production forecast, it is critical to include well and completion performance in the analysis. A new workflow is developed to assess and incorporate the damage mechanisms at the wellbore, fracture and reservoir into production forecasting. Currently, most reservoir models use a skin factor to represent the combined well damages mechanisms. The skin factor is adjusted based on the user's experience or data analysis instead of physical modeling. In this workflow, a detailed model is built to explicitly simulate the damage mechanisms, assess the dynamic performance of the well and completion with depletion, and generate a physics-based proxy function for reservoir modeling. The new workflow closes the modeling gap in production forecasting and provides insights into which damage mechanisms impact PI degradation. In the workflow, a detailed model is built, which includes an explicit wellbore, an explicit fracture and the reservoir. Subsurface rock and flow damage mechanisms are represented explicitly in the model. Running the model with an optimization tool, the damage mechanisms’ impact on productivity can be assessed separately or in a combination. A physics-based proxy is generated linking the change in productivity to typical well parameters such as cumulative production, drainage region depletion and drawdown. This proxy is then incorporated into a standard reservoir simulator through the utilization of scripts linking the PI evolution of the well to the typical well parameters stated above. The workflow increases the reliability of generated production forecasts by incorporating the best representation of the near wellbore flow patterns. By varying the damage mechanism inputs the workflow is capable of history matching and forecasting the observed field behavior. The workflow has been validated for a high permeability, over pressured deep-water reservoir. The history match, PI prediction and damage mechanism analysis are presented in this paper. The new workflow can help assets to: (1) history match and forecast well performance under varying operating conditions; (2) identify the key damage mechanisms which allows for potential mitigation and remediation solutions and; (3) set operational limits that reduce the likelihood of future PI degradation and maintain current performance.

The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest. There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells. A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility. The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions. Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements. The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased. A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed. The reduction of HSE risks through a better management of field operators is also assessed.

Historically, motor temperature analysis in electric submersible pumping systems (ESP) attracted the most attention due to the vulnerability of insulation under temperature. For wells with low or moderate downhole temperatures, motor temperature alone is not effective to protect the system against no-flow conditions. This issue has become more critical in unconventional gassy wells, many ESP failure modes are more associated to high temperatures in the pump than the motor. Under gas locking or no flow conditions when production (cooling) fluid stagnates, the pump generates much more heat than the motor and experiences a faster temperature rise becoming a serious issue for the health of the ESP. Traditional pump intake and discharge thermocouples (TC) cannot detect this phenomenon because their locations are too far from the source of heat generation. This paper describes testing where several TCs were placed in an ESP pump. Temperatures were monitored when the pump was operated through different gas volume fractions (GVF) and flow rates. A gas locking condition was also simulated in a test loop to study the transient condition. Subsequently, a thermal model was developed and compared to the testing data. The test used a fully enclosed, high-pressure gas loop. A 12-stage, mixed flow type with best efficiency point (BEP) at 600 BPD pump was horizontally mounted in a test bench. Ten TCs were installed at the bottom bearing, No.1, 6, and 12 diffuser bearing in both X and Y directions, respectively. Three TCs were attached to the pump housing on bottom, middle, and top locations. Pump intake/discharge temperature and pressure were captured during testing. The mixture volume of nitrogen and water was measured and supplied to the pump intake. Experimental data was acquired continuously for evaluating different operational conditions. The intake pressure, GVF, flow rate and rotational speeds were controlled in the experiments. In a static state, the thermal model started with energy equilibrium and calculated the temperature rise due to the difference between the pump brake horsepower and hydraulic horsepower. In a transient state, finite-element analysis (FEA) was used to predict the thermal profile from the stage bearing to the pump housing. Based on the thermal testing and modelling results, several ESP failure modes and tear-down examples will be discussed. The concept of minimum continuous thermal flow (MCTF) will be mentioned. A reservoir model was used to understand the difference in the nitrogen/water testing system and to develop the possible strategy to recover from pump gas locking. In summary, the pump temperature study provided a better understanding of the pump gas locking condition, a better method to conduct ESP health monitoring and improve reliability by avoiding overheating the pump. This paper adds a comprehensive knowledge of pump temperature analysis to the ESP industry. The results will help define the running limitations of an ESP in a gas condition and improve design, application and operation to mitigate the gas locking issue in unconventional oil production.

With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) ( Triepke 2018 ). Primary wells (formerly called "parents") ( Daneshy 2019 ) are the initial wells on the pad and infill wells (formerly called "children") are all those that follow on the pad or an adjacent pad. Failure to protect the primary well from infill well fracture driven interactions can result in up to 40% EUR losses in infill wells from asymmetric fractures ( Elliott 2019 )( Ajisafe et al 2017 ). Adverse frac interactions between wells in a DSU can be largely eliminated with a combination of primary well refracs and infill well zipper fracs. In the primary well protection process there is a movement away from "preloads" as the overall results from the preloads to date suggest they are not effective in preventing infill well frac asymmetry unless the primary well can be restored to its original stress conditions. A number of operators have announced plans in press releases to increase well spacing in the DSUs to reduce well to well interference. A number of of organic shale operators have also announced performance related reserve write downs according to a March 13, 2019 Simmons Energy report ( Harrison and Todd 2019 ). While in some cases the writedowns were due to changes in pricing expectations, the combination of a known reserve bashing situation and numerous operators still relying on preloads for parent protection raises a red flag. It is highly likely that there is a relationship between DSUs that use preloads instead of refracs for primary well protection and poor overall performance from the DSU. It was proposed in the keynote address at a recent primary-infll frac interaction conference that refraccing primary wells is significantly more effective than preloading them in preventing large infill EUR losses ( Elliott 2019 ) ( Figures 1 and 2 ). Figure (3) has a microseismic interpretation of an infill well assymetric frac offsetting a primary well with no refrac. The stranded hydrocarbons are clearly where there is no microseismic activity. For a DSU with 600,000 BO wells the combination of the 40% infill well EUR loss and the loss of up to two PUDs per DSU can be in the $29 million range so this is hardly an academic exercise. Figure 1 Depletion Mitigation Opportunities Figure 2 Depletion Mitigation Results Figure 3 Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consistent than these first two methods ( Cadotte et al 2018 ), there is now a lot of discussion on the best mechanical isolation method to use. The two most common isolation techniques are cemented conventional casing and expandable liners. The main advantage of the cemented casing is lower up initial costs, with a $123,000 difference in cost before frac operations commence for a 5000 ft refrac liner. The main advantage of the expandable liner is a larger diameter that allows for 20% to 25% higher pump rates. With the combination of the Extreme Limited Entry (XLE) completion technique and expandable liners the higher treatment rates translate directly into longer stage lengths while still maintaining high cluster efficiency. The resulting lower stage count reduces the overall stimulation cost well below the incremental initial cost of the expandable liner, with a net savings of $446,000 per refrac over the cemented liner option for a 5000 ft lateral. The savings would be higher for longer laterals as the stage number difference will increase. With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) ( Triepke 2018 ). Primary wells (formerly called "parents") ( Daneshy 2019 ) are the initial wells on the pad and infill wells (formerly called "children") are all those that follow on the pad or an adjacent pad. Failure to protect the primary well from infill well fracture driven interactions can result in up to 40% EUR losses in infill wells from asymmetric fractures ( Elliott 2019 )( Ajisafe et al 2017 ). Adverse frac interactions between wells in a DSU can be largely eliminated with a combination of primary well refracs and infill well zipper fracs. In the primary well protection process there is a movement away from "preloads" as the overall results from the preloads to date suggest they are not effective in preventing infill well frac asymmetry unless the primary well can be restored to its original stress conditions. A number of operators have announced plans in press releases to increase well spacing in the DSUs to reduce well to well interference. A number of of organic shale operators have also announced performance related reserve write downs according to a March 13, 2019 Simmons Energy report ( Harrison and Todd 2019 ). While in some cases the writedowns were due to changes in pricing expectations, the combination of a known reserve bashing situation and numerous operators still relying on preloads for parent protection raises a red flag. It is highly likely that there is a relationship between DSUs that use preloads instead of refracs for primary well protection and poor overall performance from the DSU. It was proposed in the keynote address at a recent primary-infll frac interaction conference that refraccing primary wells is significantly more effective than preloading them in preventing large infill EUR losses ( Elliott 2019 ) ( Figures 1 and 2 ). Figure (3) has a microseismic interpretation of an infill well assymetric frac offsetting a primary well with no refrac. The stranded hydrocarbons are clearly where there is no microseismic activity. For a DSU with 600,000 BO wells the combination of the 40% infill well EUR loss and the loss of up to two PUDs per DSU can be in the $29 million range so this is hardly an academic exercise. Figure 1 Depletion Mitigation Opportunities Figure 2 Depletion Mitigation Results Figure 3 Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consistent than these first two methods ( Cadotte et al 2018 ), there is now a lot of discussion on the best mechanical isolation method to use. The two most common isolation techniques are cemented conventional casing and expandable liners. The main advantage of the cemented casing is lower up initial costs, with a $123,000 difference in cost before frac operations commence for a 5000 ft refrac liner. The main advantage of the expandable liner is a larger diameter that allows for 20% to 25% higher pump rates. With the combination of the Extreme Limited Entry (XLE) completion technique and expandable liners the higher treatment rates translate directly into longer stage lengths while still maintaining high cluster efficiency. The resulting lower stage count reduces the overall stimulation cost well below the incremental initial cost of the expandable liner, with a net savings of $446,000 per refrac over the cemented liner option for a 5000 ft lateral. The savings would be higher for longer laterals as the stage number difference will increase. With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) ( Triepke 2018 ). Primary wells (formerly called "parents") ( Daneshy 2019 ) are the initial wells on the pad and infill wells (formerly called "children") are all those that follow on the pad or an adjacent pad. Failure to protect the primary well from infill well fracture driven interactions can result in up to 40% EUR losses in infill wells from asymmetric fractures ( Elliott 2019 )( Ajisafe et al 2017 ). Adverse frac interactions between wells in a DSU can be largely eliminated with a combination of primary well refracs and infill well zipper fracs. In the primary well protection process there is a movement away from "preloads" as the overall results from the preloads to date suggest they are not effective in preventing infill well frac asymmetry unless the primary well can be restored to its original stress conditions. A number of operators have announced plans in press releases to increase well spacing in the DSUs to reduce well to well interference. A number of of organic shale operators have also announced performance related reserve write downs according to a March 13, 2019 Simmons Energy report ( Harrison and Todd 2019 ). While in some cases the writedowns were due to changes in pricing expectations, the combination of a known reserve bashing situation and numerous operators still relying on preloads for parent protection raises a red flag. It is highly likely that there is a relationship between DSUs that use preloads instead of refracs for primary well protection and poor overall performance from the DSU. It was proposed in the keynote address at a recent primary-infll frac interaction conference that refraccing primary wells is significantly more effective than preloading them in preventing large infill EUR losses ( Elliott 2019 ) ( Figures 1 and 2 ). Figure (3) has a microseismic interpretation of an infill well assymetric frac offsetting a primary well with no refrac. The stranded hydrocarbons are clearly where there is no microseismic activity. For a DSU with 600,000 BO wells the combination of the 40% infill well EUR loss and the loss of up to two PUDs per DSU can be in the $29 million range so this is hardly an academic exercise. Figure 1 Depletion Mitigation Opportunities Figure 2 Depletion Mitigation Results Figure 3 Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consistent than these first two methods ( Cadotte et al 2018 ), there is now a lot of discussion on the best mechanical isolation method to use. The two most common isolation techniques are cemented conventional casing and expandable liners. The main advantage of the cemented casing is lower up initial costs, with a $123,000 difference in cost before frac operations commence for a 5000 ft refrac liner. The main advantage of the expandable liner is a larger diameter that allows for 20% to 25% higher pump rates. With the combination of the Extreme Limited Entry (XLE) completion technique and expandable liners the higher treatment rates translate directly into longer stage lengths while still maintaining high cluster efficiency. The resulting lower stage count reduces the overall stimulation cost well below the incremental initial cost of the expandable liner, with a net savings of $446,000 per refrac over the cemented liner option for a 5000 ft lateral. The savings would be higher for longer laterals as the stage number difference will increase.

Implementation of a drift-flux (DF) multiphase flow model within a fully-coupled wellbore-reservoir simulator is non-trivial and must adhere to a number of strict requirements in order to ensure numerical robustness and convergence. The existing DF model that can meet these requirements is only fully posed for upward flow from 2 degrees (from the horizontal) to vertical. The work attempts to extend the current DF model to a unified and numerically robust model that is applicable to all well inclinations. In order to achieve this objective, some 5805 experimentally measured data points from 22 sources as well as 13440 data points from the OLGA-S library are utilized to parameterize a new DF model – one that makes use of the accepted upward flow DF model and a new formulation extending this to horizontal and downward flow. The proposed model is compared against 2 existing DF models (also applicable to all inclinations) and is shown to have better, or equivalent, performance. More significantly, the model is also shown to be numerically smooth, continuous and stable for co-current flow when implemented in a fully implicitly coupled wellbore-reservoir simulator.

Standard history matching workflows use qualitative 4D seismic observations to assist in reservoir modeling and simulation. However, such workflows lack a robust framework for quantitatively integrating 4D seismic interpretations. 4D or time-lapse seismic interpretations provide valuable inter-well saturation and pressure information and quantitatively integrating this inter-well data can help to constrain simulation parameters and improve the reliability of production modeling. This paper outlines technologies aimed at leveraging the value of 4D for reducing uncertainty in the range of history matched models and improving the production forecast. The proposed 4D Assisted History Match (4DAHM) workflows utilize interpretations of 4D seismic anomalies for improving the reservoir simulation models. Design of Experiments (DOE) is initially used to generate the probabilistic history match simulations by varying the range of uncertain parameters. Saturation maps are extracted from the Production History Matched (PHM) simulations and then compared with 4D predicted swept anomalies. An automated extraction method was created and is used to reconcile spatial sampling differences between 4D data and simulation output. Interpreted 4D data is compared with simulation output, and the mismatch generated is used as a 4D filter to refine the suite of reservoir simulation models. The selected models are used to identify reservoir simulation parameters that are sensitive for generating a good match. The application of 4DAHM workflows has resulted in reduced uncertainty in volumetric predictions of oil fields, probabilistic saturation S-curves at target locations, and fundamental changes to the dynamic model needed to improve the match to production data. Results from adopting this workflow in two different deep-water reservoirs are discussed. They not only resulted in reduced uncertainty, but also provided information on key performance indicators that are critical in obtaining a robust history match. In the first case study presented, the deep-water oil field 4DAHM resulted in a reduction of uncertainty by 20% in OOIP and by 25% in EUR in the P90-P10 range estimates. In the second case study, 4DAHM workflow exploited discrepancies between 4D seismic and simulation data to identify features necessary to be included in the dynamic model. Connectivity was increased through newly interpreted inter-channel erosional contacts, and sub-seismic faults. Moreover, the workflow provided an improved drilling location which has the higher probability of tapping unswept oil and better EUR. The 4D filters constrained the suite of reservoir simulation models and helped to identify 4 out of 24 simulation parameters critical for success. The updated PHM models honor both the production data and 4D interpretations, resulting in reduced uncertainty across the S-curve and, in this case, an increased P50 OOIP of 24% for a proposed infill drilling location, plus a significant cycle-time savings.

High water-cut has been observed for many multi-fractured horizontal wells (MFHWs) in China soon after waterflooding begins. Available well-testing models of single well ignored the effect of adjacent wells on the MFHW, and they are unable to evaluate whether MFHW (producer) and surrounding vertical wells (injectors) are in good pressure communication. To fill this gap, this work presents a multi-well interference testing (MWIT) model to consider the interference of injectors and further match the interference pressure data. The MWIT model is established to investigate the effect of multiple injection wells on transient-pressure behavior of the MFHW. Due to the interferences from injectors, the pressure and pressure-derivative curves of MWIT move down beginning with the biradial flow regime for single MFHW model, and pseudo-radial flow (horizontal line with the value of 0.5 on pressure-derivative curve) disappears. Sensitivity analysis was conducted to discuss the effects of crucial parameters on the pressure response, including total injection rates, unequal injection rates of injectors, well spacing, injector distribution, number and production of hydraulic fractures. When total injection rates are lower than the production rate, the pressure derivative will eventually stabilize at 0.5*(1-Σ( q IncjD )) during the interference-flow regime on the log-log type curves. Since only the positive number can be shown in the log-log graph, semi-log curves are also developed to fully characterize the flow regimes of MWIT. A novel finding is that pressure derivative also ultimately behave as a horizontal line with the value of 0.5*(1-Σ( q IncjD )) when total injection rates are equal or higher than production rates on the semi-log curves. The total injection rates and well spacing between the MFHW and injectors have a significant effect on middle and late pressure behaviors, whereas the number and production of fractures mainly affects the pressure responses during early to middle period. Type curves indicate that the effect of surrounding injectors are significant and cannot be ignored, and the novel characteristics provide potential application of the MWIT model to estimate formation parameters. Case studies highlight the application of the proposed method in effectively matching the interference pressure data. Interference-testing analysis of the MWIT provides a better reservoir evaluation compared to single-well testing model.