An oil and natural gas producer should continuously analyze industry fundamentals such as supply, demand, storage, transportation, and pricing to make informed operational and business decisions. An oil and gas producer should be able to adapt to frequently changing industry environment by adjusting its operation: increasing or curtailing production, drilling and connecting new wells, obtaining new financing, locking in future natural gas prices, etc. In order to provide an input to the decision-making process, the adaptive management methodology needs to be applied. Forecasts of hydrocarbon resources, production, infrastructure, and pricing are very sensitive to technological improvements, pricing changes, new discoveries, and other major events, the impacts of which are difficult to predict. One method to improve the quality of a forecast is to apply adaptive management process. The adaptive management methodology implies assuming supply and demand strategy, creating multiple scenarios for allocating oil or gas demand to different areas or regions, evaluating these scenarios, and performing detailed forecast for selected scenarios. One important step of adaptive management is monitoring of actual drilling and production activities. Based on this information original assumptions can be updated. The result of the analysis is production, prices, and infrastructure forecast. The paper presents an example of a production forecast that is generated using adaptive management process.

The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases. Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results. The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.

The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells. The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries. The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others. As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations. With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.

This paper evaluates the impact of decision making and uncertainty associated with production forecast for 2000+ wells completed in Permian basin. Existing studies show that unconventional reservoirs have complex reservoir characteristics making traditional methods for ultimate recovery estimation insufficient. Based on these limitations, uncertainty is increased during the estimation of reservoir properties, reserve quantification and, evaluation of economic viability. Thus, it is necessary to determine and recommend favorable conditions in which these reservoirs are developed. In this study, cumulative production is predicted using four different decline curve analysis (DCA) − power law exponential, stretched exponential, extended exponential and Duong models. A comparison between the predicted cumulative production from the models using a subset of historical data (0-3months) and actual production data observed over the same time period determines the accuracy of DCA's; repeating the evaluation for subsequent time intervals (0-6 months, 0-9 months,) provides a basis to monitor the performance of each DCA with time. Moreover, the best predictive models as a combination of DCA's predictions is determined via multivariate regression. Afterwards, uncertainty due to prediction errors excluding any bias is estimated and expected disappointment (ED) is calculated using probability density function on the results obtained. In this paper, uncertainty is estimated from the plot of ED versus time for all wells considered. ED drops for wells having longer production history as more data are used for estimation. Also, the surprise/disappointment an operator experiences when using various DCA methods is estimated for each scenario. However, it appears that whilst Duong (DNG) method always overpredicts, power law exponential (PLE) decline mostly under predicts, the stretched exponential lies between DNG & PLE estimates and the extended exponential DCA demonstrates an erratic behavior crossing over the actual trend multiple times with time. In conclusion, profitability zones for producing oil in the Permian basin are defined implicitly based on drilling and completion practices which paves the path to determine the "sweet spot" via optimization of fracture spacing and horizontal length in the wells. The outcome of the paper helps improve the industry's take on uncertainty analysis in production forecast, especially the concept of expected disappointment/surprise. This study suggests that effects of bias due to decision making can be much greater than what has often regarded, which can change the performance evaluation of the Permian basin in terms of economic feasibility.

The separation of gas from gas-liquid mixture in horizontal wells has become a growing concern in the oil and gas industry. The produced free gas reduces the efficiency of rod pump systems, minimizes oil production and can lead to the failure of the rod pump system due to gas locking phenomena. The impact of two-phase flow on the new horizontal well gas anchor’s performance was investigated experimentally. Each experiment was conducted in a transparent horizontal well flow loop by using water and air as the test fluids. Experiments with and without the new gas anchor in the flow loop cases were studied. The new tool has two mechanisms to prevent gas phase from entering the tubing. The first mechanism is the breakage of the mixture’s wave by the bull plug of the tool. The second mechanism is the separation of small gas bubbles due to the flow through the tortuous path inside the tool. This experimental program quantifies the tool performance regarding the first working mechanism only. The bubble separation via the tortuous path mechanism was not investigated. The results showed that both with and without tool cases can separate 90 – 100% gas from the mixture, if the inlet of tubing or the tool was fully submerged under liquid phase of the mixture at all time. This condition was achieved under stratified flow where the horizontal part of the well was toe flat or toe-up (0°, +1°, and +2°). The wave breakage mechanism by the bull plug of the tool was confirmed visually. This breakage mechanism established the advantage of using the new gas anchor over no-tool condition.

Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift. Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time. The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.

This study analyzes the production data from 2,755 horizontal wells in the Haynesville shale. Correlations were generated to predict 4,5,6, and 7-year cumulative productions from initial 6,12 and 24-months production data. These correlations can help in field development planning and economic analysis. The residuals (Predicted – Actual Cumulative Production) from these correlations were also analyzed and this technique can be used to identify wells affected by interference, refracturing, frac-hits, etc. The cumulative production estimates from the developed correlations were also compared with the corresponding estimates from the DCA equations (seven different DCA methods used). The accuracy of prediction based on correlations developed in this study is at par with the various standard DCA methods published and used in the industry. The correlations are much faster to use and easier to implement for a large number of wells. Another objective of the paper was to develop P10, P50 and P90 type curves for the Haynesville shale using the available production data. A subset of the total wells i.e. 150 wells evenly distributed throughout the study area, were used for predicting type curves. These type curves were generated and compared using different Decline Curve Analysis (DCA) models. The different DCA methods predicted an uncertainty of 5 to 27 % for the P10, P50 and P90 production profiles.

Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.

Over the past 20 years the industry has focused on drilling and completing horizontal producing wells, in order to develop better deliverability and better UER across the reservoir. The past 10 years igniting the unconventional reservoirs across the US the majority of wells drilled and completed are horizontal wells. These types of wells are traditionally drilled with various inclinations, trajectories which porpoise across the reservoir interval. Horizontal lateral sections consist of numerous selectively stimulated stages containing greater than 20 stages spread out across 2,000 ft to 15,000 ft of horizontal interval. In order to understand how a producing horizontal lateral section contributes, is to deploy production log technology across the lateral while the well is flowing back. The production log system & survey is the only direct method to measure the performance of the well, how each stage and perforation cluster contributes, oil, water and gas. The production log tool comprises of various measurements such as fluid capacitance, fluid density, holdup, which measures the oil, water gas content, cross sectional holdup and velocity as fluids enter the lateral section. The production log system can be deployed with two separate methods, coiled tubing deployment or wireline with a well tractor situated on top of the production log tool string. It is highly recommended that the production log survey be performed using a procedure and program created by an experience specialist production logging personnel. This will increase the probability the service will deliver a representative result & value to the oil company. However, whether by customer decisions, inadequate service company knowledge, lack of experience in how the tools and deployment methods should be run & how the well should be performing during the survey; the production log surveys, at time may not deliver a quality product. A full service production log service including deployment, the price point offering is ~ $100,000 to > $1,000,000. A slip up in service quality leads to the service not being performed in the future or leaves a negative view on the service over all. This paper will discuss the benefits pit falls of horizontal production log survey application, deployment & acquiring quality results. The paper will show case examples of productions logs run with various deployment methods & identify benefits and issues during the survey. This paper will present a best practices novel procedural flow-chart for the industry to follow, that can assist and help production logging, wireline, tractor, coiled tubing deployment service companies, and the oil company engineering group to execute properly a quality production log service survey.

In response to the low hydrocarbon price environment, most operators have decreased the number of rigs actively drilling wells ( Cui 2016 , Chapman et al. 2016 ). However, the production decline in wells completed in a given timeframe has undergone far more change than the count of active rigs. In many cases, wells must be drilled to meet contractual lease obligations but are not being completed due to uncertain economic conditions. Type curves are valuable tools to predict future performance of such drilled-but-uncompleted (DUC) wells by analyzing results of existing wells exhibiting similar characteristics. It is reasonable to assume, while considering reservoir characterization and completion engineering, that existing wells can predict the performance of future wells. However, to generate a larger sample size with which to construct the type curves, data can be normalized by a particular variable. A normalized curve is then scaled by an adjustment associated with the new well to produce its expected production profile. This same process also allows type curves to be applied to other areas with different reservoir properties or completion parameters. Analysis focuses on applying normalized type curves to estimate DUC well performance and populate a ranking system to guide the completion planning process. Reservoir material balance and surface network simulation are also utilized to understand subsurface effects and identify possible facility constraints above ground. Additionally, there is a brief discussion regarding type well best practices to aid in the analysis.

Conventional laboratory methods for obtaining relative permeability in oil and gas shales are difficult if even possible to obtain. Insight can be gained from high pressure mercury injection and the relative permeability obtained there from using pore throat models. An integrated approach between relative permeability derived from core laboratory pore throat models with production analysis allowed us to generate new type curves that can be used with field production to determine Brooks Corey wetting phase exponents. A procedure utilizing laboratory mercury injection capillary pressure on core samples from the Bakken reservoir is used to generate a distribution of wetting phase saturation exponents and residual wetting phase saturations for numerical simulation model input. Model output is normalized by the time and cumulative oil production at the onset of boundary dominated flow to generate type curves that can be used to successfully history match field production in the Bakken formation in North Dakota. A new type curve has been developed in which oil production and transition from linear to boundary dominated flow are the two requirements needed to derive oil-gas relative permeability. The median of wetting phase saturation exponents for the Middle Bakken formation ranges between values of 2.3-2.6. Other useful results from the combination numerical simulation and field production data study include the prediction and observation of an elevated yet constant producing gas oil ratio during the linear flow period (prior to boundary dominated flow.) Several consequences of this result allows selection of proper application of decline curve analysis techniques, properly determine initial solution gas oil ratio for fluid characterization, and indication of relative permeability prior to the onset of boundary dominated data.

Low concentration particle transport in multiphase horizontal pipes in the presence of a viscous liquid is experimentally investigated using a 0.05 m diameter pipe. The experiments were conducted for a wide range of liquid and gas flow rates in both intermittent and stratified flow. Critical velocity was defined as “minimum required liquid and gas flow rates to keep particles constantly moving in the pipe”. Critical velocity is defined in a way to make sure all particles are continuously moving along the pipe and as a result prevents forming a stationary bed of sand. The experimental data obtained in the current study shows that the required gas flow rate to meet critical velocity definition increases by decreasing liquid flow rate. Moreover, the effect of physical parameters such as sand concentration, sand size and liquid viscosity is also experimentally investigated. The experimental data obtained in this study shows that critical velocity is a function of sand concentration and sand size and increases by increasing either within the examined range of particle concentration and size. Regarding the effect of carrier liquid viscosity, the experimental data reveals that by increasing viscosity the minimum required flow rates to constantly move sand along the pipe increases.

The optimization of stimulation treatments in Mexico has required the use of novel diversion technologies to increase the productivity of wells by improving the coverage of stimulation fluids and reducing completion costs. Self-degrading particulate has become widely used in the country because of the diverter flexibility. Job experiences range from hydraulically fracturing unconventional reservoirs to the matrix acidizing of naturally fractured carbonate formations. The purpose of this paper is to verify the effectiveness of this material for achieving the selective stimulation of multiple intervals, either in horizontal or vertical wells. Because there is no confidence in a complete stimulation of all open intervals, diagnostic techniques have been implemented to determine the effectiveness of diversions. For near-wellbore (NWB) monitoring, technologies such as radioactive tracers and distributed temperature sensing (DTS) have been used to determine treatment fluid locations after the application or in real-time. Downhole microseismic monitoring has been performed for far-field indications of diversion success in hydraulic fractures of vertical wells with multiple intervals open at the same time. This paper discusses four wells from the north, central, and south regions in Mexico. All of them have completely different reservoir properties and completion types. Improved production increase was the main difference between wells where diversion with self-degrading particulate diverters was used compared to those that were not treated with diverters; a production increase from 30 to 70% was achieved. Completion time was reduced with the implementation of the novel self-degrading particulates vs. other possible methods, allowing faster return of investment (ROI). Real-time decision making could be performed using both a diverter and monitoring techniques to assure a uniform treatment placement. Another differentiator was the simple logistics required to handle the material compared to other additives employed in the past. Because of the performance of the diverter, it has been applied in more reservoirs with extremely variable permeabilities across the country (tight gas and oil sandstones, gas and oil shales, and naturally fractured oil-bearing carbonates). Downhole temperature is the main controlling factor to accelerate or retard the degradation of the particulate, as it must take into account that in cooler formations, longer times are required to achieve complete degradation. Its independence of the wellbore geometry has increased the implementation in openhole and cased-hole completions, despite the final shape of the perforations.

Produced Water Treatment (PWT) technologies have evolved significantly over the past 15 years. In 2001, the first Compact Flotation Unit (CFU) was introduced to the oil and gas industry on the Norwegian Continental Shelf. Today, this well-proven technology, which separates residual oil from produced water (PW), operates worldwide. CFUs function either in the facility's PW train as a final step downstream from a separator in various configurations, or as a standalone treatment system in the slop/reject treatment process system. Our analysis shows that it is possible to substantially improve conventional CFU oil separation performance. A portion of small gas bubbles that have been in contact with oil droplets will never rise to the top of the CFU vessel due to countercurrent water flow. Instead, they exit at the bottom of the unit. Removing a larger portion of these small bubbles in flotation technology will achieve an additional decrease of oil-in-water (OiW). Because of their high surface-to-volume ratio, removing small gas bubbles helps move more oil away from the PW discharge. Schlumberger development of next-generation CFU technology included theoretical study, benchmark lab testing and field trials. To improve separation efficiency, we implemented several new internal designs within the same external CFU size and design, and analyzed them in a computational fluid dynamics (CFD) model. For manufacturing and further lab- and field-testing, we selected a final design that considerably improved oil-separation efficiency. The new technology delivers two-stage oil separation in a single vessel. Each stage uses a different mechanism to improve oil separation. Results from lab testing show that the new CFU increases oil-separation efficiency up to 45% compared with existing technology. Key benefits of the new design include: Less impact on the environment through improved OIW discharge figures Lower skid weight through fewer vessels (one instead of two) Reduced facility footprint through smaller skid size Retrofittable technology We based the new CFU design on CFD analysis, testing in a PW flow loop, and an offshore field trial which also verified better oil separation performance. Results from the field trial indicated the new CFU improved performance 27 % compared with conventional technology. This was achieved while maintaining the outer CFU dimensions and design.

In the past decade, Hydrogen Sulfide gas has begun to appear in many Barnett Shale gas wells. As more wells are drilled and hydraulically fractured, larger populations of bacteria are introduced to the formation resulting in the current concentrations of H 2 S that are observed today. In addition to a lack of biocide treatments, wells are often hit by fracs from other producers in the area. As the fractures in the rock converge, new bacteria are introduced that were at first only present in a neighboring well. This idea of fracture convergence prevents treating the problem at the source, as operators cannot control well contamination caused by other companies. The rapid rate at which bacteria are growing and spreading demonstrates a clear problem. To prevent H 2 S concentrations from further increasing, it is critical that a sustainable field treatment program is developed and implemented. The completed study involved an analysis of 96 wells operating under the biocide treatment method, continuous wet-gas injection method, and continuous dry-gas injection method. The study took into account gas flow rate, H 2 S concentration, produced water rate, and chemical usage rates. The results yielded a final $/MMCF value for each well under its respective treatment method. The results of the study showed first that specific treatment options apply to specific circumstances. For example, the iron sponge media proved to be the most effective long term mitigation option while the scavenger chemical flow loop design provided the adequate retention time required for lower concentrations of H 2 S. Furthermore, there was no clear evidence that disproved the effectiveness of conventional biocide treatments. According to test results conducted before and after separation, dry gas chemical treatment proved to be more efficient than wet gas treatment. Because H 2 S is not native to the Barnett Shale, many operators are only recently discovering problem wells. This report provides in detail, the pros and cons of a variety of different treatment options accompanied with field-study results. Other operators can use this information to safely develop and improve their H 2 S treatment programs.

Mature gas wells tend to suffer from flow rate fluctuations due to an inability to remove liquids. Flow-rate stabilization is essential for profitable operation of these wells. Moreover, the use of nozzles can help make in-situ foam treatments more efficient. The combined use of venturi nozzles and foamers is proposed as a novel artificial lift method. The effect of downhole venturi nozzles on flow stabilization of gas wells has been experimentally investigated. Air-water flow was studied in a 2″ vertical pipe. The effect of the nozzles on in-situ foam generation was also studied. Using the principles of Nodal Analysis, it was observed that the use of downhole venturi nozzles significantly improved the stability of production. The nozzles induce back-pressure on the flow inlet. The smaller the throat diameter is, the greater the back-pressure is. Therefore, proper sizing of the nozzle is important. Flow through the nozzles was characterized using CFD simulations and a sizing methodology has been proposed. Foam flow was studied for injection before and after the nozzle at very low concentrations of a commercial foamer. The presence of the nozzle during foam flow did not affect the pressure gradient or holdup characteristics significantly when compared to foam flow without nozzle. However, the foam stability and quality were affected by the nozzle, depending upon the position where the foamer was injected (either before or after the nozzle).

Liquid loading is the inability of a riser or gas well to produce liquids, resulting in reduction of gas production in mature gas fields. Mechanisms describing liquid loading initiation are not well understood for inclined pipes or deviated wells. Knowing the effect of pipe inclination over the liquid-loading initiation will help for the development of a predictive tool for flow assurance, well production forecast as well as remediation techniques enhancing gas production. An experimental study of low liquid loading has been conducted for 90°, 75°, 60° and 45° inclined pipes. Air/water flow in a 3-in ID pipe has been investigated. Pressure gradient and average liquid holdup were measured. Visual observations with high and low speed cameras have been recorded to identify flow patterns and liquid film behavior for each test point. Pipe inclination effects on critical gas velocity for flow pattern transition have been investigated. The critical gas velocity represents the maximum gas flow rate where the liquid loading is observed. This critical velocity increases as pipe inclination deviates from vertical. Pressure gradient fluctuations and liquid film flow behavior are closely related with liquid loading initiation. As the pipe deviates from vertical and owing to the increasing liquid film thickness at the bottom of the pipe, slug and churn flow patterns are promoted. Therefore, the existing critical velocity prediction models, which ignore the circumferential variation of film thickness, produce significantly different values of critical velocities when compared with the experimental data. Liquid loading is one of the main problems that the industry faces during the production of natural gas wells and transportation of low liquid loading gas-liquid flow through a riser. This study serves as a foundation for future model developments to avoid and remedy liquid loading related problems in risers and gas wells.

The effect of pipe diameter on liquid loading initiation has been experimentally investigated using 2-in and 4-in pipe diameters. Two-phase flow parameters such as pressure gradient and liquid holdup were measured. Flow characteristics were determined by visual observation using a high speed video camera. Critical gas flow rate for liquid loading initiation has been identified and comparison between the two pipe diameters is presented. The critical superficial gas velocity corresponding to the minimum pressure gradient is larger for the smallest diameter. When the comparison is carried out in terms of mass flow rates, critical flow rate for liquid loading in 2-in pipe is smaller than that in 4-in. pipe. This supports the use of velocity strings to extend the production life of the gas well. Additionally, comparison of the data with available mechanistic models prediction shows significant discrepancies. Possible reasons for these discrepancies are presented.

Interwell connectivity, an important element in reservoir characterization, especially for secondary recovery such as waterflooding, is essential when making decisions on well patterns, infill wells, and injection rates for oil recovery optimization. An existing technique uses multivariate linear regression analysis of flow rates in a waterflood to infer interwell connectivity. Advantages of this technique include a simplified one-step calculation and the availability of production data. A capacitance model was introduced as an extension of the technique to account for shut-in periods and changes in bottomhole pressures in the producers; however, this approach is based on trial and error and requires subjective judgment. This paper presents an alternative analytical approach based on analytic concepts, providing an in-depth understanding of the technique and relationships between interwell connectivity coefficients and other reservoir parameters. The analytical approach uses a mathematical model for bottomhole pressure responses of injectors and producers in a waterflood system. The model is based on a solution for fully penetrating vertical wells in a closed rectangular reservoir with an assumption of steady-state flow. This model is then used to calculate relative interwell permeabilities, which represent the connectivity levels of signal response well pairs. Different synthetic reservoir models were analyzed, including homogeneous, anisotropic reservoirs, and reservoirs with high-permeability channels and transmissibility barriers. Comparisons with results obtained from previous studies of production data and bottomhole pressure data are presented. The main findings of this study are: (a) the mathematical model performs well with interwell connectivity coefficients calculated from flow rate data to quantify reservoir parameters; (b) the proposed approach provides a better understanding of interwell connectivity determination from flow rate data;and (c) the results for relative interwell permeability from flow rate data are similar to those obtained from previous studies of bottomhole pressure data.

The decline curve analysis (DCA) is one of the most important methods in production forecast. It has been widely used among all the dynamics methods to estimate recoverable hydrocarbon. Decline curve can be divided into three categories: exponential decline, hyperbolic decline, and harmonic decline. Superficially decline curve analysis is the simplest prediction method, but as we dig into the base for DCA we find that it is not as simple as we think before. The opinion that DCA just follows the production trend can lead to tremendous errors, or even ridiculous results. A good DCA requires a solid background in reservoir engineering, production engineering, and even drilling engineering. In-depth knowledge is necessary on studied reservoir, surface production facility, and the drive mechanism. In this study, several tactics developed from experience are applied to get practical and effective DCA and some pitfalls are pointed out to avoid the error or inappropriate forecast in DCA. With these tactics and pitfalls in mind, DCA can be a very useful and powerful tool in predicting recoverable hydrocarbon. Applying the established tactics and acknowledged pitfalls presented by this paper would lead to an accurate production forecast and reasonable reserves evaluation.