The ability to effectively transport sand without the use of guar-based fluids has led to the development of friction reducers that build viscosity. These new products, also known as high viscosity friction reducers (HVFR) generate viscosities comparable to or greater than linear gel fluids. The selection criteria have focused primarily on achieving greater than 10 cP at 300 RPM (511s-1). As the salinity of the base fluid changes, the HVFR dosages must be increased up to 4X to meet this target. However, there is limited data available on how this viscosity correlates to the fluid’s ability to transport sand. This study presents methodology used to screen HVFR’s in various fluids and results on product performance, which identifies need for alternative specifications to viscosity. The sand transport capacity under dynamic conditions was evaluated for two commercially available HVFR’s in up to 120,000 TDS synthetic water. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow conditions. The viscosity and elasticity were also measured using an advanced rotational rheometer. For comparison, a linear gel fluid was also evaluated. While viscosity targets can be achieved by many commercially available HVFR products in freshwater, when salinity is increased, these products fail to meet the same targets. A comparison of the viscosity versus the sand transport capacity of these fluids, suggests viscosity does not indicate sand carrying capacity. The author did not find a correlation between higher viscosity and better sand transport. The results provided insight into the effect of flow rate on sand transport. The effect of salinity on s and transport suggests good performance can be achieved even at low viscosity. Elasticity testing of those same products suggested that HVFR’s have a critical elasticity range at which they will provide optimal performance. This paper provides insight into the HVFR properties which correlate to sand transport and highlights the need for development of standardized test criteria other than viscosity. Further testing and screening of HVFR’s will increase the understanding of key factors influencing sand transport.

The continually evolving water management practices of liquids-rich tight oil operators (for optimizing the water use and costs of their water life cycle) is a topic of major impact. One area during the produced water phase of the water life cycle, is the less understood effect of different water cut fractions of the total fluids production from the formation on both the producing three-phase flow rate trends on surface as well as the downhole multiphase flow conditions, in particular, lateral to bend slugging and loading tendencies. This paper quantifies this effect of varying water cut production in a variety of operational conditions. In order to quantify the effect of varying water cut production, the methodology of this work involves first understanding the basic differences between gas-and-water (100 % water cut) and gas-and-oil (0% water cut) multiphase production in terms of their averaged slip behaviors, and therefore, total pressure gradient observations. We utilize published lab-scale flow loop experiments and a few actual, field-scale wells to demonstrate the different reported behaviors. An analytical multiphase flow simulator is then validated against these observations. Once verified, we then use the simulation tool to perform downhole calculations of flowing bottomhole pressure, gas volume fraction (gas-liquids slip), wellbore flow pattern, difference in wellbore and critical gas velocities and slugging flow characteristics (slugging frequency, velocity and lengths) for a given set of surface operating conditions. The workflows presented in this work will enable a deeper insight into the differences between gas and liquids slip under varying water cut fractions in both lighter condensate fluids as well as denser black oil fluids production. This work adds an improved understanding of the effect of water cut fractions on the total pressure gradient behaviors and downhole multiphase flow slugging and loading behaviors in liquids-rich tight oil developments.

Accurate EUR estimation is a critical component of the oil and gas asset evaluation process and has become increasingly important in de-risking investments in shale plays. Hybridized decline curve analysis has emerged as an industry-wide best practice for this process. This method of interpretation is dependent on the accuracy of the estimated terminal decline rate or switch point. Accurately predicting the terminal decline rate for wells with insufficient production history, has proven difficult. This issue is further aggravated in emerging basins and regions of development, as well as complications associated with parent-child relationships in developed acreages. The present paper tackles these challenges by using a statistical approach to predict the switch point and onset of terminal decline rates in unconventional shale plays. Typical production profiles in unconventional shales are marked by high initial declines and long transient flow regimes, followed by a transition to boundary dominated flow as the pressure transient reaches the boundaries of the effected reservoir. The decline rate at this switch point, as well as the duration to get to it can vary significantly and is dependent on a wide range of variables. The present paper tackles this multivariable problem by using an ACE (alternating conditional expectation) non-linear regression model to predict the switch point. Variables used to predict this change in flow regime include: Gamma Ray, Resistivity (Deep), RHOB, NPHI, formation thickness, WOR, GOR, completion design, proppant amount per foot, perforated interval, and production performance amongst others. In order to account for the impact on production, behavior from infill development and parent-child relationship discrepancies, date- dependent 3D well spacing was calculated and incorporated as a variable in the statistical model. This process was tested and applied to a large dataset of wells in the middle Bakken formation in the Williston Basin. The transformations derived from the ACE models increased clarity on the most significant factors driving Terminal Decline. For this study, the resulting transformations from the geological attributes proved most intriguing and provided insight to the physical limits of each. A few important parameters include formation thickness, neutron porosity (NPHI), and reservoir thickness. The "sweet spot" for (NPHI) was determined to be ∼6-8% and lies flat with NPHI values greater than ∼8.5%. Physically, this would correlate with decreased hydrocarbon potential due to the decrease of pore volume below ∼8.5%. Interestingly, Terminal Decline increased as reservoir thickness increased which is counter intuitive to traditional rock properties. Finally, wellbores with a lateral length of ∼10,500' or greater experienced the largest decrease in terminal decline rate. One potential explanation is the variability of the geology the wellbore encounters. The ACE models derived during this study were used to determine the most significant factors impacting terminal decline and will be discussed further within the full study. The present paper provides a novel approach to estimate the transition point to de-risk EUR estimates across shale plays. This analysis adds to the existing body of literature by using data analytics and machine learning to tackle this problem from a truly multivariable standpoint. The insights developed are widely applicable and may provide best practices for a varied range of challenges in EUR prediction.

Unconventional reservoirs, characterized by their ultra-low permeability and porosity, have complicated production mechanisms yet to be fully understood. Gas produced from unconventional oil reservoirs are majorly classified as the secondary product, with the focus on oil. However, gas plays a vital role in the production of oil from unconventional plays and can be economically beneficial as well. Therefore, while oil production forecasting is highly important, it is equally imperative to figure out ways in which solution gas production can be forecasted. There has been very little information in the literature about forecasting solution gas production. The huge question is - can we possibly forecast gas-oil ratios and ultimately, solution gas production? And if we can, can we do that with some reasonable level of certainty? This paper attempts to answer these questions by exploring the use of an Asymmetrical Sigmoid Model (ASM) to forecast gas-oil ratios (GOR) and solution gas production. Asymmetrical sigmoid functions have been applied in several fields of study such as biology, finance, agriculture, etc. Research into the possibility of employing the use of this type of function for predicting future GOR values, arose from studies and observation of the nature of GOR profiles of wells in unconventional oil reservoirs. This paper presents a new approach to forecasting gas-oil ratios and solution gas production - the Asymmetrical Sigmoid Model (ASM). A commercial compositional reservoir simulator was used to simulate 30 years of production from multi-fractured horizontal wells (MFHW) with different reservoir fluids. Further, ASM was used to forecast producing gas-oil ratios from the wells with production histories ranging from six months to 3 years. The results were compared to simulated GOR data. Solution gas production were then calculated from the estimated producing gas-oil ratios using the trapezoidal rule and compared to simulated solution gas production data as well. This methodology was similarly applied to field data from various wells in different shale oil reservoirs and the results were compared to the available historical field data. In recent years, factors such as limited production data, complex flow mechanisms of liquid-rich shale reservoirs, production pattern of producing gas-oil ratios among others, have made the task of forecasting GOR and solution gas production difficult. However, ASM enables us to have a simple functional approach that empiricallymimicsthe basic pattern of producing GOR profiles in unconventional oil reservoirs quite well. ASM also helps to forecast gas-oil ratios and solution gas production with reasonable measures of accuracy. After the application of ASM to available historical data, and comparing the results with simulated and field data, there were relatively low error percentages in majority of the cases considered. Due to the continuous rise in global demand for energy, and its corresponding economic implications, the importance of research focused on improving and finding new ways of accurately forecasting oil and gas production cannot be downplayed. This work presents aninnovative and easyway offorecasting gas-oil ratios and solution gas production from unconventional oil plays. It is a valuable contribution to the ongoing efforts of research into better and simpler ways of forecasting production from unconventional reservoirs. Findings from this work can help to improve reserves estimation, reservoir management, field development planning and overall project economics.

In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play. To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence. The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.

In this continuation work, we expand upon the Nagoo et al., SPE-190921 [ 1 ] seminal paper that unveiled for the first time a simple and direct analytical critical gas velocity diameter-and-inclination-dependent equation for predicting the onset of liquids loading in horizontal wellbores. Using this equation, we now introduce a new analytical method for quantifying lost liquids production in liquids-rich horizontal gassy oil and gas wells undergoing liquids loading. Case studies of in-operation horizontal wells from the Permian and Delaware basins are used to highlight and validate the methodology. For horizontal liquid-rich wells in unconventional plays, liquids loading can severely impair production in gassy oil or gas wells with significant oil or water production. Currently, there is no reliable, field-focused, simple-to-use, analytical method for quantifying the lost (or deferred) liquids production because of the liquids loading happening in the wellbore. We propose that the downhole wellbore gas velocity and the critical gas velocity profiles can be superimposed on the traditional wellbore lift curve to yield a varying unloading point on the wellbore lift curve that is very sensitive to and dependent on the predictive reliability of both the diameter-and-inclination-dependent critical gas velocity model used and the wellbore multiphase flow model used. In looking at the new gas velocity-based lift curve results for several horizontal wellbores, the lost liquids production can now be quantified and compared to the actual liquids production drop in the well history before and after the onset of liquids loading. Furthermore, it is demonstrated that as opposed to prior ad hoc recommendations of bottom-of-lift-curve or tangent-of-lift-curve demarcation points for liquids unloading, the new analysis presented provides an analytical intersection point between the downhole wellbore gas and critical gas lift curves as the basis for the unloading point (onset of flow liquids flow reversal point). This signifies that the combination of analytical multiphase flow wellbore and analytical critical gas velocity calculations will now change and define the range of unloading producing rates according to diameter, inclination and fluid property changes. For the first time, a practically useful and simple analytical method for quantifying lost liquids production in liquids loaded horizontal gassy oil and gas wells is presented in the form of gas velocity-based lift curves. This signifies a new powerful arm of horizontal well artificial lift modeling for life-of-well lift optimization (i.e., incorporating rate declines) for keeping wells flowing at flow rates to avoid liquids loading. Both the lost liquids and lost gas production can be predicted on a well-by-well basis and wells can now be prioritized for artificial lift needs according to their downhole "loading proximity". Various relevant field case studies are used to validate the method in practice.

Holistic understanding of well operations can play a key role in optimization and maintenance of assets. The traditional process for understanding well operations mainly involves fitting a curve through all of the historical production data and extending the curve to forecast production without modeling the stochastic nature of production history, considering impact of any well interventions, or feeding any a priori information into curve-fitting workflows. This leads to unreliable production and reserves estimates which, in turn, impact the strategy and planning process for asset management. A novel workflow was developed learns the production characteristics of a well through a statistical framework using principles of signal processing and Bayesian inferences. Using this workflow, high-fidelity empirical production performance forecasts can be obtained for all the wells in the asset in an automated fashion. This novel workflow aims to significantly simplify interpretation of well operations, reduce the turnaround time for analyzing and modeling well performance, and improve the quality of reserves estimates.

As a major unconventional resource play, the Williston basin contributes more than 10% of total U.S. crude oil production. Due to significant concerns about net present value and payback period, the process to select the optimum artificial lift method has always been a top priority for operators. In this case study, we investigate the potential artificial lift strategies for new wells in Williston basin. The objective is to propose an artificial lift strategy that handles the challenges associated with unconventional resources and that maximizes the asset value. In this study, a novel workflow that replaces subjective decisions with objective analysis has been applied for the process of selecting the lifting strategy that will best achieve an operator's goal based on analysis of technical criteria and economic calculated results. An initial prescreening is performed to narrow down the number of applicable artificial lift systems that will meet the technical challenges of the well. Then, the selected artificial lift methods are evaluated combining a steady state flow simulator and a reservoir model to determine the well performance and response to each lift system. This response is integrated with an economic model to determine the net present value of the proposed strategy. Different strategies and sensitivities on key parameters as oil price, expected production, and water cut are performed to determine the optimum artificial lift approach. The ability to include future well performance based on a reservoir model helps in building a strong analysis that goes beyond current well conditions and includes the changes that occur to the reservoir during the production phase, such as pressure depletion and consequent production decline. Those changes drive the need to switch from one artificial lift system to another as conditions evolve. The workflow allows the user to determine the best time to start the selected artificial lift system and the appropriate transition time to a second artificial lift method. For the Williston basin case study, only electric submersible pumps (ESP) and jet pumps (JP) can be implemented during the high-flow-rate period. As production declines, a transition to a lower-flow-rate method is required. Hydraulic rod pump systems are considered the most appropriate transition method because they make it possible to pump the required volumes from deep installations. A production forecast is combined with two different water cut scenarios to evaluate the impact on the economic results of the project. The successful use of this workflow has proven its ability to analyze the life cycle of an unconventional well and establish a process for artificial lift selection. Furthermore, the current workflow is flexible enough to be extended to other fields with different input variables.

Unconventional reservoir production in the Midland Basin heavily depends on successful hydraulic fracturing treatments. Operators have been demonstrating that better wells have been completed with longer laterals, tighter stage and cluster spacing, and that the long-term well performance depends on completion effectiveness and well spacing. In this paper, we used reservoir simulation to examine optimal cluster spacing and well spacing with four adjacent Lower Spraberry horizontal wells located on the University Lands. Finding the best practice of cluster spacing and well spacing throughout the University Lands is one of the current priorities for the newly formed Texas Oil and Gas Institute (TOGI), which is part of the University of Texas System. The industry has employed different approaches to represent unconventional horizontal wells in reservoir simulation models. In this paper, we built a dual porosity model to represent the naturally-fractured reservoir with planar hydraulic fractures and associated enhanced zones. Prior to using reservoir simulation, we conducted rate-transient analyses to examine flow regimes, well interference, completion size, and cluster efficiency, and then estimated initial values such as fracture half-length, matrix permeability, and initial dual-porosity model properties. Two adjacent well pads with four horizontal wells were selected for this study. The basic production data indicated that the second set of wells interfered with the first two older/parent wells during their hydraulic fracture treatments with communication between the wells observed at a distance of roughly 1700 feet. This offset well interference affected the parent wells’ oil and water production rates. Although the rates recovered to their original trend, one of the well's productivity indexes did not recover. Using these data, the reservoir simulation model was calibrated with the observed bottomhole pressures and daily oil, gas, and water production rates. After achieving a successful history match, the model was varied to include varying cluster and well spacing, and production forecasts were developed. Then, the simulation results were evaluated using a relatively simple economic model to determine net present values. The paper provides suggestions to maximize estimated ultimate recovery (EUR) with optimized cluster spacing and well spacing to benefit both the operator and the landholder. Tighter cluster spacing maximizes well productivity and enhances well economics, and may improve ultimate recoveries. Operators have ongoing field tests to determine the apparent limit of cluster spacing based on production, operational feasibility, and the additional costs and benefits. The optimal well spacing is essentially dependent on the fracture half-length, which is an uncertainty. Accurate determination of hydraulic fracture half-length is the key to optimize the well spacing and requires additional analyses such as microseismic monitoring, fiber-optic sensing to determine cluster efficiency, and modeling of hydraulic fracture dimensions.

Operators in the Permian Basin continue to advance their knowledge on unconventional horizontal wellbore constructions for optimal production. However, it is often assumed that drilling and completing the longest possible laterals is the obvious solution. Motivations to drill and complete the longest possible laterals could come from either maintaining lease agreements held by production, reducing cost, and/or reducing the surface foot-print. Wells with high tortuosity wellbores will experience liquid holdup along the lateral, thus, it might be a better solution to drill wells as uniform as possible to avoid undulations. Therefore, analyzing the effect of production over time due to various wellbore trajectories is necessary to advance our understanding of production optimization. This paper demonstrates the workflow to determine optimal lateral lengths and trajectories in the Midland Basin by studying the impact of the lateral length and trajectory on well production performance. This study couples reservoir simulation models with transient multiphase wellbore models. The reservoir simulation model is first calibrated with historical well production data. The calibrated model is then used to forecast the long-term well productivity. The long-term productivity is then used to study the impact of wellbore trajectory and lateral length on well performance. This paper details the following multiphase flow simulation cases: (1) horizontal wellbores with vertical deviations, and (2) horizontal wellbores with vertical deviations and tortuosity, combining with different lateral lengths, and reservoir and production conditions. For each case, the paper compares the impact on well production, liquid holdup, and EUR potential at different production time steps. The workflow has been applied to two University Land wells in the Midland Basin. The University Land wells pertain to one Lower Spraberry well from the Northern Midland Basin and one Wolfcamp B well from the Southern Midland Basin. At least one operator has statistically shown that uniform, toe up wells yield higher productivity and production potential. However, the study also reveals that long lateral lengths do not completely ensure proportionately more production, and wells with high tortuosities could hinder production potential. Wellbore lateral lengths and uniformity are important for production optimization to minimize liquid holdup and maximize productivity throughout the wells’ production lives. However, wellbore construction designed for holding leases and completed under time constraints could negatively impact production and limit operators’ potential for their acreage. To determine an optimal lateral wellbore length, it is necessary to study wellbore multiphase flow behavior and resulting production for unconventional horizontal wells.

Liquids-rich gas plays present significant challenges to producers to keep wells flowing and maximize production. In particular, liquid loading is a frequent issue as production rates decline and flow rates are no longer sufficient to keep liquids entrained in the gas stream. Many strategies exist and have been attempted over the years for attempting to keep these wells flowing and avoid liquid loading. Perhaps the most attractive option is wellhead compression, which will lower wellhead pressures and increase flowrates, both items necessary to eliminate liquid loading. By reducing wellhead pressures, compressors will also increase the recoverable assets of a well. Traditional compression is not able to operate with liquids present and thus requires additional infrastructure and facilities to separate, store, and transport the liquids. Multiphase production facilities are a good solution to eliminate the need for additional infrastructure at the wellhead, and instead move the multiphase flow downstream to a central facility for processing. However, the more common multiphase pump technologies suffer from low efficiencies in the high gas volume fraction (GVF) conditions typical in liquids-rich gas wells. A new multiphase compression technology is identified with the potential to achieve the benefits of multiphase production while operating at efficiencies closer to a traditional compressor. Testing is conducted with the new technology on several different wet gas wells in the Eagle Ford. Testing shows that the compressor is successfully able to handle a multiphase stream coming directly from the well without any additional separation facilities. Additional testing further demonstrates that the compressor may even be able to unload a well that is already loaded. Further testing and development work will be required to broaden the conditions at which the compressor can operate and to prove that it can successfully maintain a variety of different wells flowing above their critical rates and unloaded. Initial indications are very promising and suggest that the new compressor technology will be a powerful tool for producers to use in maximizing the production of liquids-rich wells.

Development projects in unconventional reservoirs can require capital expenditures of several hundred million to several billion dollars. Therefore it is essential that the assessment of these projects be as objective and unbiased as possible – that begins with the selection of analog production type curves. Economic analysis of any development project is highly dependent on the production schedule incorporated into the cash flow model. For unconventional resource plays, project production schedules are often based on the aggregation of production type curves for an average, or representative, well within the defined project area. In general, we rely on the most representative analog wells available to define the production type curve. In established projects, these analogs typically come from the most recent wells within the project area; for new plays, the “best” analogs may be located in a different basin or play. But regardless of the data used to build type curves, the question emerges, “How do I know if my analog production type curve is representative?” This paper presents methods for building aggregation models using Monte Carlo simulation to: Create confidence curves to evaluate the confidence of meeting pilot objectives as a function of the type curve uncertainty and the number of wells in the pilot; Generate Sequential Accumulation plots which project cumulative initial production rates for pilot projects onto a forecast envelope consisting of a cumulative P10-P90 envelope. By plotting the cumulative initial rates as pilot wells are brought online, the evaluator can assess whether the modeled type curve is appropriate or if it is conservative or optimistic. Included in the paper are several examples comparing pilots that validate the selected type curve with pilots showing potential bias in the analog type curve. An important observation from these curves is the impact of sample size (e.g. the number of pilot wells) on the predicted confidence of meeting pilot objectives and the assessed validity of the analog type curve.

Development of liquid rich shale (LRS) reservoirs has gained tremendous momentum in recent years. A detailed understanding of fluid behavior, completion practices and reservoir dynamics is essential to accurately predict their long-term performance. This paper uses stochastic reservoir modelling to identify the optimal values for several completion and uncertainty parameters. A compositional reservoir simulation model for a typical gas condensate well in the Eagle Ford shale was used to identify the optimal production strategies for maximum EUR of oil and gas. The important factors considered for the study are fracture spacing, fracture conductivity, fracture half-length, well spacing, porosity, permeability, initial GOR and well constraints. These factors are often studied independently of one another and their interaction is usually ignored. For example, in a higher permeability play, greater fracture density leads to rapid recovery but ultimate cumulative production does not improve. However, for a play with lower permeability, greater fracture density improves both recovery rate and EUR thereby leading to improved overall economics. Thus, interaction effects due to coupling can have a decisive effect on the overall performance of a reservoir. This paper presents a statistical study of both independent and coupled effects on ultimate oil and gas production from a LRS gas condensate reservoir. The results show that fracture half-length and fracture spacing have the most complex and significant effects on performance of the reservoirs studied. High initial rates are often preferred in unconventional reservoirs with their rapid rates of decline. These high rates can be achieved with larger fracture half-lengths and smaller fracture spacing. This study shows that high initial rate of production leads to a greater liquid dropout and larger condensate banking. These results also reduce the production rate of gas due to relative permeability effects. Return on investment is reduced due to reduced cumulative production and excess spending on fracture creation. Similar effects were observed for other factors like well constraints where higher minimum flowing bottom-hole pressure led to lower cumulative gas production and lower liquid dropout. In some cases higher bottom-hole pressure might be preferable due to the differential in the price of condensate and gas. The sensitivity studies in this study provide considerable insight into the long-term production behavior in LRS gas condensate reservoirs. During the initial phase of a project, uncertainties related to various field parameters and their coupled effects are often ignored leading to suboptimal returns on investment.

Arps' decline model was developed for the boundary dominated flow (BDF) regime that is reached quickly in conventional reservoirs. Without modification, the Arps model does not work well for unconventional reservoirs with long-duration transient flow and variable bottom-hole pressure. This paper presents results of a study of different decline models that are used to forecast production in LRS reservoirs with long-duration transient flow. The study used synthetic future production data generated using reservoir parameters typical of those observed in practice. In traditional DCA, a single curve is fitted to the entire production data without using the historical pressure data. However, the first step in reliable DCA is to identify the different flow regimes using appropriate diagnostic plots and then fitting different flow regimes with different models. This procedure allows us to forecast future production using appropriate decline models. The results from the study show that log-log pressure-normalized vs. time diagnostic plots correctly identify flow regimes in low permeability LRS plays. Pressure normalization removes the confounding effects of multiphase flow and variable pressure and allows us to predict the time at which we need to switch from transient to boundary-dominated-flow (BDF) DCA models. Pressure normalization can be used on rate restricted wells which would otherwise be not possible using only rate data. Hybrid models, in which early transient linear flow is fitted by models like Duong, or SEPD, followed by the Arps' decline model during BDF, were significantly more accurate than single-flow-regime models. The results from the study also showed that there is a long transition period between early transient linear flow to BDF due to the onset of multiphase flow. Each flow regime, including the transition flow regime, was modeled by calculating appropriate model parameters from available rate-pressure-time data. Hybrid models forecasted the gas EUR accurately. Condensate production was also estimated by using a method proposed by Yu which led to accurate forecasts for lean gas condensate samples. LRS gas condensate reservoirs have fundamentally different flow behavior than traditional black oil/dry gas reservoirs, and we cannot forecast rates using traditional decline curve analysis without modification. We can use diagnostic plots to select appropriate decline curve methodology based on the type of reservoir fluid.

The selection of perforation zones in unconventional reservoirs can be very challenging. Great strides have been made by the integration of both engineering and geological data. However, a successful perforation zone selection methodology in one Basin might not be successful in another. This paper presents a pilot study on a perforation zone selection and zonal contribution in a vertical well in the Midland Basin. Reservoir characteristics as well as the geomechanical properties of a formation are important in the selection of optimum locations for limited entry perforations. In this work, several data sets, including openhole logs, radioactive tracer logs, amount of proppant pumped, PVT sampling, and 3D fracture modeling were integrated. Additionally, temperature logs were used to identify zonal contributions during the early flowing period. Results from this work indicate that closure stress is the dominant parameter greatly affecting the fracture initiation and growth in the observed well while both high and low brittleness sections were observed similar behavioris of hydraulic fracture failure. Learnings from radioactive proppant tracers and 3D fracture modeling efforts helped to identify the importance of closure stress in addition to brittleness in perforation placement identification. Temperature log interpretations were correlated with proppant tracers and fracture modeling which qualitatively indicates that the Lower Spraberry and Wolfcamp B formations are big contributors to production and thus good potentials targets for horizontal wells.