Long known for its tolerance of solids-laden fluid and wellbore deviation, gas lift is an increasingly popular artificial lift method for horizontal unconventional wells. A variation of gas lift known as Single Point High Pressure Gas Lift (SPHPGL), noted for the absence of gas lift valves, is now practical because of the availability of high discharge pressure compression equipment. In SPE 187443 ( Elmer 2017 ), the authors of this paper proffered that Annular SPHPGL could lift large liquid volumes. Further, this lift method was potentially a competitive alternative to failure prone Electric Submersible Pumps (ESPs) which are often used early in the life of horizontal wells to produce at high rates. The authors provided Nodal Systems Analysis to support this claim but lacked actual data from field testing. Finally, they appealed to industry to implement and perfect this "not new" but timely technology. When the referenced paper was presented at the October 2017 SPE ATCE, high pressure compressors were not available from industry for lease. This situation changed in early 2018, with rental equipment becoming available in the Permian Basin. Subsequently, a Permian Basin operator (SM Energy) agreed to perform a pilot test in Howard County, Texas to test the conclusions listed in the paper, primarily that Annular SPHPGL could compete rate-wise with ESPs. Plans for a pilot test were made. Additionally, the production facility was modified to handle the possibility of higher flowrates than normally observed with ESPs, as well as increased slugging. Injection down the tubing with returning flow up the tubing-casing annulus began in September 2018. Initial production rates were close to Nodal Systems Analysis predictions, and comparable with ESP flowrates. This proved that this technique could in fact compete rate-wise with ESPs. For operators using liquids-rich produced gas for gas lift, the importance of maintaining gas temperatures elevated throughout the compression process is documented. Also, the positive results of the production facility modifications to handle higher flowrates and possible slugging are presented.

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.

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.

The Woodford shale formation of Oklahoma is difficult to evaluate and forecast for production. Horizontal wells can often be inconsistent with offset wells, either in production rate or in expected ultimate recovery. The costs of these wells can vary greatly based on the cost and effectiveness of the fracture treatments used. Treatment can be difficult, and production rates do not always indicate open flow paths to the well. Various logging techniques were applied in an attempt to overcome some of these treatment issues. Ideally, the imposed treatment will create a large surface area within the formation with continued, open flow paths from the contact surface in the reservoir to the wellbore. Because this is a rock mechanical problem, logs that can deliver a solution for relative rock mechanics were added to the logging program. Dipole sonic logs delivered the most consistent solution. The paper provides a case study in which these data were applied in the Woodford formation in Oklahoma. In this study, a vertical pilot hole was drilled, dipole sonic logs were run, and rock mechanical values were calculated. The dipole sonic logs were run in casing in the horizontal wellbore. Anisotropy was calculated from these data. The fracture treatments were designed using rock mechanical information from both data sets. This paper compares the results of the pilot well data with an offset well in which the acquired data were not used to alter treatments and initiation locations. Also, a comparison to an offset well is included, where dipole sonic in the horizontal were the only data acquired. In both cases, the better data set resulted in better completions.

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.

The purpose of this study is to review the applications of laws of thermodynamic in petroleum system, and how it may be lead to optimum operating conditions and miximize substantially the ultimate hydrocarbon recovery, optimizing at the same time the reservoir energy utilization. In this paper is shown how thermodynamic concepts such as energy, efficiency, availability function, useful work, and entropy generation were introduced in petroleum engineering to explain losses of fluid energy due to reservoir exploitation. It was remarked that a proper management of variables such as production or injection rate, wellbore vicinity condition (skin factor), number of wells and their locations, locations of surface facilities, reservoir driving mechanisms, and improved hydrocarbon recovery techniques, all of them from a thermodynamic point of view, should be considered if both the reservoir energy efficiency and its sustentability are a must. More valuable applications may be extended from the concept of entropy generation, such as its inclusion in reservoir simulation as a post-processing calculus, in order to generate and compare multiple realizations for seeking an optimum operating condition, and maximizing hydrocarbon recovery at the scenario of minimum irreversibility.

A common industry problem in many flowing gas wells is the gradual build-up of well-bore fluids across the perforations over time. This phenomenon, commonly referred to as liquid loading, is typically seen in many wells that are low-producing, low in pressure, or have long perforation sets. A new gas well de-watering system has been developed to combat this problem, utilizing the reservoir’s energy to help keep it unloaded. This system utilizes a production packer, tail pipe, and carrier subs containing pressure regulating devices in order to trap and use formation gas to keep the well unloaded beneath the packer. This paper will take a closer look into the system through a study of field examples where it was implemented. In the study, one specific well from the US West Rockies Region will be chronicled from the original diagnosis of the liquid loading problem, to the design and installation of the system. Analysis plots are shown to illustrate its success. Additional field examples, within the same and different US fields, will be included to give further illustrations of this de-watering system, while also exemplifying and detailing the system’s limitations in an unsuccessful installation. A comparison analysis will be included and a discussion of lessons learned. The implementation of this system on properly selected wells can significantly impact the performance of low-producing gas wells where liquid loading destroys productivity levels over time. Although it can be run in conjunction with conventional artificial lift, this system introduces a way of utilizing the reservoir’s energy to keep it flowing naturally for a longer period, before artificial lift is necessary. This helps to reduce the overall well costs at a time when the industry is dominated by many tight, unconventional gas wells.

During the last five years, many shale gas plays have emerged, such as the Woodford, Haynesville, Fayetteville, Marcellus, Eagle Ford, etc. However, the Barnett Shale is the most mature of the currently producing gas shale plays in the US. Understanding the production mechanism and the production decline characteristics of the Barnett Shale will contribute to a better understanding of how newer shale plays will behave in a longer term. A production decline curve analysis (DCA) in the Barnett Shale is presented that incorporates public production data from over 8,700 horizontal wells. This analysis is performed by grouping wells based on years on production. Production data are normalized to zero-time, and regression history-matching is performed to estimate decline curve parameters. Long-term production is forecasted for 30 years. Production decline results strongly suggest hyperbolic decline. Particularly, the b value ranges from 1.3 to 1.6. First-year decline rate ranges from 56% to 74%. Thirty-year cumulative production ranges from 2.0 to 3.0 Bscf. The Best 12-month average gas rate and first 24-month cumulative gas production show a consistent trend and correlate very well with the predicted 30-year cumulative gas production. In spite of the advancement in completion and drilling practices, the gas recovery from newer wells is slightly worse than that of the older wells. This may be attributed to the poorer reservoir quality outside the core area or interference between wells due to down-spacing. Wells producing more than 5 years are often restimulated using hydraulic fracturing techniques. It is still too early to tell the impact of re-stimulation on ultimate gas recovery. However, the re-stimulated wells all show an increase in the short-term well productivity.

Horizontal wells that are to be stimulated with transverse fractures are usually completed either openhole with annular isolation packers or cemented. Fluid communication is established by perforating or using stimulation sleeves. The industry continues to grapple with several issues regarding these completions, such as what the optimum number of fractured intervals is, and which approach (openhole versus cemented) provides the best hydrocarbon production. Analysis was performed to create a simple method for determining the production impacts of increasing the number of fractured intervals in a horizontal well. The intent was to create something similar to the McGuire-Sikora curves (method of determining the production impacts of fracturing vertical wells) for horizontal wells with transverse fractures. Using the McGuire-Sikora curves allows for a quick assessment of productivity gains associated with fracture stimulating a vertical well. Analysis was performed using a two-dimensional reservoir simulator using a steady-state edge drive. A methodology was developed, and is described, for including the effects of vertical to horizontal permeability ratios in a two-dimensional simulator. Analytical results showed productivity-index ratios as a function of relative conductivity for different fracture geometries. The resulting curves were used to estimate production gains of fracture stimulation compared to the openhole, unstimulated case. The variables included in the analysis were reservoir permeability, vertical to horizontal permeability ratio, reservoir thickness, reservoir length, fracture half-length, fracture width, fracture permeability, fracture spacing along the horizontal, and openhole and cemented completions. In this paper, comparisons are made to published works that use production data and microseismic data to compare openhole and cemented completions. The analysis presented should help fuel the industry debate of whether cemented completions are an overused solution.

Abstract The Granite Wash formation in Oklahoma is made up of arkosic detrital material resting on older Precambrian rocks. It can range in age from Precambrian to Middle Pennsylvanian. Formed by erosion of uplifted segments, it is generally granitic in nature; it may also include large areas of reworked carbonate. This wash presents a very difficult log interpretation problem since reservoir consistency varies greatly from well to well. Magnetic resonance image logs were added to the logging program to establish additional parameters that could be used for reservoir description. The standard Coates permeability equation and its variations were applied to estimate permeability with little correlation to production. An observation was made that T2 bin distribution data tended to mirror production rates. Attempts were made to establish an algorithm that would directly establish permeability for this formation using measured T2 data. By matching actual production rates to observed T2 distribution data, we developed an equation to estimate permeability. This case study presents the results of using T2 bin information for estimating permeability and includes several Granite Wash wells. Introduction Middle Pennsylvanian Atoka age granite and carbonate wash along the Witchita Mountain Front, Anadarko Basin, western Oklahoma, poses one of the most difficult log interpretation puzzles in the continental United States. Deposited as a series of overlapping, submarine fans where the clastic source material is Cambro-Ordivician Arbuckle Limestone, the formation is complex and inconsistent from well to well. Figure 1 exhibits the general deposition of the formation.

Abstract Mature fields lack the sparkle of a new play, and an operator typically will not invest capital for waterflooding, much less EOR. But prevailing higher oil prices can turn such a mature oil field more profitable by employing innovative production enhancement techniques. We propose the use of a simple, tapered tubing string completion (using larger internal diameter (ID) tubing pipes in the upper sections) that can be customized for specific reservoirs. Historically there are few instances of tapered ID tubing completion, which were basically necessitated by technical constraints (liner, workover, etc.). But our approach is focused on enhancing economic performance. We have employed nodal analysis technique to develop an equivalent tubing diameter (ETD) concept. The ETD allows for comparing the well performance for single-ID tubing completion. The procedure also seeks an optimum length for the larger tubing ID in the upper section. Using reservoir simulation for full life cycle, and oil prices projected over time until abandonment, the economic performance is evaluated using NPV and other economic parameters. The proposed production enhancement method is suitable for wells with moderate to high open flow potentials (AOFP). It is especially suited for low GOR wells with high future water-cut that will eventually require an ESP system, and also remote oilfields, where reservoir pressure maintenance and EOR is not viable. The use of larger tubing ID section entails only a marginal increase in CAPEX. However, the tapered completion gives increased production rate sustained over a long time, which results in significant economic gain. The economic benefits accrue from the prevailing high oil price, yielding a quick payout and many returns on investment. The proposed completion approach does not involve complexity, and the innovative application of nodal analysis coupled with high oil prices show how to make mature oil fields onshore and offshore, more profitable. Introduction Nodal analysis was performed in the sixties and seventies by hand calculations, using vertical pressure traverse graphs generated in-house by big oil companies. Smaller operators, if they at all used nodal analysis, relied on Brown's (1963) famous pressure traverse graphs. The workflow was tedious at best, discouraging engineers to explore for horizons that nodal analysis could lead to. However, with the advent of affordable PC software (e.g., Fekete's FAST™, IHS's PERFORM™, etc.), and even MS-Excel™ based spreadsheet programs (e.g., Guo et al. 2007), the power of nodal analysis now can be unleashed even in a classroom setting. One such unexplored horizon is tapered tubing string design - with gradually larger internal diameter (ID) in the upper sections of tubing string. Conventional tubing string design entails selecting a constant internal diameter for all the tubing sections—from bottom to top. The upper sections of the string, however, have a greater wall thickness to support the load of the string below. Thus conventional tubing strings are tapered in terms of outer diameter, which is necessitated by mechanical loading requirements.

Abstract Progressing cavity pumps (PCPs) have proven to be a successful and reliable artificial lift system for production of heavy oil reservoirs over the past few decades. The application of PCP technology for production of oil wells in general continues to expand rapidly due to ongoing advances in versatility, production rate and lift capacity, durability, and economy. As a result, the application envelope for PCP systems has grown substantially to the point where these systems now successfully compete in many areas that were traditionally reserved to Rod Pump and ESP technologies. The development and implementation of a new type of PCP, namely the "all metal" (non-elastomeric) progressing cavity pump has been driven by the need to achieve significant improvements in the performance and run life of PCPs in high temperature/thermal well applications, and wells producing fluids which cause rapid chemical and/or mechanical degradation of elastomeric PCPs. This paper describes the successful implementation and use of Metal PCP systems in a diverse range of extra heavy oil wells located along the northern coast of Cuba beginning in July 2005. This is believed to be the first major use of this technology in such a field application. The paper also compares the performance and run lives achieved with the Metal PCPs to that of elastomeric PCPs in the same application. In general, the field trial results have demonstrated that the strong resistance of Metal PCPs to chemical and mechanical degradation makes them a good alternative for the cold production of heavy and extra heavy oil with relatively high bottomhole temperatures and high aromatic, CO2 or H2S concentrations. Introduction Progressing cavity pumps (PCPs), first developed and patented by Rene Moineau (Moineau, 1931), have found numerous applications in many industries as a means to efficiently transfer, transport and/or lift fluids of a diverse nature. The use of PCPs as an artificial lift method for oil wells has gained increasing acceptance since their first commercial use in heavy oil applications in the 1980's, and they have now become the lift method of choice in numerous oil field developments worldwide (Doval et al, 2007). This paper describes the use of PCP systems to produce extra heavy oil from a number of extended reach horizontal wells located along the northern coast of Cuba. The field experience includes numerous conventional (elastomeric) PCP installations over the past 8 years, as well as the deployment of several recently developed "all metal" PCPs beginning in July 2005 - this is believed to be the first major use of this new technology in such a primary production application. Relevant field data has been collected and analyzed to assess and compare the performance and service life of the various conventional and all metal PCPs.

Abstract In some heavy oilfields, oil can flow in the reservoirs but may not flow through the wellbore without taking measures such as heating or diluting with light oil because of the high viscosity caused by low temperature around the wellbore close to surface. We focused on the latter issue in this study which is being widely used in Tah oilfield and other oilfields in China. Since the viscosity of the crude oil changes with temperature significantly, accurate prediction of wellbore temperature profiles is of great importance to determine the injection rate and temperature of light oil for dilution. An analytical model was derived to predict the wellbore temperature profiles for the heavy oil production assisted with the addition of light oil from the annulus. The model was based on energy balance between the formation and fluids flowing through each conduit. The temperature profiles were calculated using the proposed temperature model and the results were compared with the measured data. Sensitivity analysis was conducted using the proposed model and the main factors that influence the temperature profiles were discussed. Introduction Tah oilfield is one of the ultra-deep and ultra-heavy oil reservoirs in China. Most wells are deeper than 5000 m. Tah oilfield is also featured of high temperature (130oC) and high water salinity (over 100,000 ppm). Although the oil can flow in the reservoir easily (this may be because of the high reservoir temperature), it cannot flow to the surface in many wells. The main reason may be because the viscosity of the crude oil increases greatly in the upper part of the wellbore due to the low temperature around the wellbore at the shallow depth as a large amount of heat loses to the formation. In Tah oilfield, one of the solutions to this problem was to inject light oil with much lower viscosity through the annulus to the crude oil in the tubing. This approach has been being extensively applied in Tah oilfield and other oilfields in Xinjiang, China. Accurate prediction of the wellbore temperature profile is important to determining the values of the parameters (for example, the amount of light oil that should be added) in the design of the dilution projects because the oil viscosity varies significantly with temperature. There have been many papers on the calculation of the temperature profiles in the wellbore under different production conditions but few in the cases in which light oil is injected from the annulus to mix with the produced crude oil in the tubing. The physical process and heat-transfer in the case in which heavy oil is produced by adding light oil are similar to those in gas-lift wells. However there are some differences between the two cases. For example, the heat-transfer is of different characteristics for gas and light oil; the viscosity of the crude oil in the tubing is reduced significantly after mixing with the light oil injected from the annulus, which may affect the heat-transfer. Ramey (1962) might be the first to present a theoretical model to estimate fluid temperature as a function of well depth and production time. The model proposed by Ramey (1962) has been widely used in both geothermal and petroleum industries. However, the effects of kinetic energy and friction were ignored in the model proposed by Ramey (1962) and therefore the model is only applicable to single-phase flow. The approach reported by Satter (1965) improved Ramey's model by honoring the effect of phase change during steam injection. There have been many modified temperature models (Shiu and Beggs, 1980; Sagar, et al., 1991; Alves, et al., 1992; Hasan and Kabir, 1994 and 1996; Jurak and Prnic, 2005) for two-phase flow in wellbore since Ramey (1962) proposed the theoretical temperature model. Sagar et al. (1991) extended Ramey's model to multiphase flow in wellbore by considering kinetic energy and Joule-Thompson expansion effects. Hasan and Kabir (1996) reported a mechanistic model for circulating fluid temperature. Hasan et al. (1996) presented a model for gas-lifting wells.

Abstract Permeability enhancement [1], which is due to the sand produced from disturbed zone around wellbore, is the key mechanisms to improve the oil production rate in CHOPS. This has lead to the demand for the accurate predicting methodology to the amount of sand production. In this paper, a new integrated spread-erosion numerical model was developed, in which sand is produced from disturbed zone, and its dynamic performance depends on the spreading of wormhole which is determined by the pressure gradient between wormhole tips and reservoir. Also sand is fallen off from sand wall which is depends on the erosion parameter. Mechanisms case study shows that sanding will continue for a while even when the spread of disturbed zone is pause, as sand wall erosion is another source of sanding. Compare with wormhole lab testing data and sanding well monitoring data, sanding dynamic performance which is simulated by this new model is more reasonable and more reliable. 1 Introduction CHOPS is often associated with high drawdown and solid production. Understanding of its mechanisms and affect factors is very important to the field operations to make sure the oil production could be enhanced. There are three types of mathematical model: skin factor, mobile permeability and wormhole spreading, which are applied in most commercial simulators to describe the dynamic performance of sanding and oil production in CHOPS. 1.1 Skin factor model Production enhancement from sanding is substituted by a negative skin factor. It's simple and runs fast. However, the performance of sanding and wormhole spreading in the disturbed zone cannot be study through this model. Furthermore, it is difficult to determine a reasonable skin factor to match the real sanding case. 1.2 Mobile permeability model Theoretically, there is a relationship between porosity and permeability. Assume a distance from the disturbed zone boundary to the wellbore sand wall, and then the change of porosity and enhancement of permeability from sanding is evaluated. Finally, the production rate could be predicted. However, the behavior of spreading in disturbed zone is not shown in this model and the production rate is estimated incorrectly either. 1.3 Wormhole spreading model Based on the fractional and geomechanical theories, the wormhole network simulator, in which the dynamic spreading performance is involved, is developed. Sanding behavior is corresponding with the spreading of disturbed zone, and oil is produced from wellbore and wormhole network. In this model, sanding is happened only at the tips of wormhole. However, it is verified by core experimental data that sand is also produced from sand wall in wormhole. Erosion is ignored in this wormhole spreading model. More complicated methods are developed and presented by researchers and sanding experts in recent years. Rock geomechanics and reservoir seepage mechanisms are fully coupled, in which the spreading of disturbed zone, dynamic sanding performance and oil production rate are predicted quantitatively. However, these simulators are not flexible enough during applied in field as their highly complex with low running efficient. Furthermore, some geomechanical input data, which are required in these models, are not available in field. As a result, forecasting of sanding behavior and production performance through these models are affect by lots of uncertain factors. Based on the analysis of sanding experiment and field monitoring data, sand is produced from 2 sources, one is the spreading of wormhole tip due the pressure gradients exceed the residual cohesion of rock; another is the erosion from sand wall in wormhole.

Abstract Xinzhao oilfield, a naturally fractured low-permeability field in Daqing, was put into development in 2000 using an inverted nine-spot waterflood pattern with 300m×300m well spacing. Although waterflooding at Xinzhao oilfield had been an economic success, performance had generally been considered disappointing because oil response following expansion and waterflood adjustment was always less than predicted, so an integrated study aiming to improving the development effect of Xinzhao oilfield was conducted. This paper presents the results of a study addressing the impact of fractures on the recovery and on the reservoir management in pattern waterfloods. Geological study and reservoir performance study indicate that several factors result in this seemingly unfavorable performance, one of main reasons are that the inverted nine-spot pattern is not compatible with the orientation of fractures. The production wells on the row of injectors are seriously watered-out and watercut increases very fast. Reservoir simulation studies indicate that oil cut can be improved if the injection pattern is modified from current inverted nine-spot well pattern to direct line drive pattern to take advantage of orientation of fractures. A field test project based on these studies has yielded results that indicate improved economic performance and better development effect. Introduction Waterflooding is the oldest and by far the most important method used by the petroleum industry to increase recovery from both onshore and offshore reservoirs(Singh et al., 1982). Waterflood design is a complex problem that must ultimately be handled on an individual reservoir basis. The waterflood development requires a substantial investment in wells and facilities and optimizing the number and location of well will be key to the success of waterflood project(Jones et al., 1997). Determing the optimum pattern is one of the major challenges associated with the design and implementation of a waterflood or any other drive processes(Christman, 1994). Fractured low-permeability reservoirs contain a large volume of the worldwide oil resource (Saidi, 1983), yet production from these reservoirs has been modest. Taking Daqing oilfield as an example, the total non-producing reserves in Daqing oilfield is 5.36×108 ton, 3.30×108 ton of which is in low permeability reservoirs, accounting for 82.9% of total non-producing reserves(Xia et al., 1996). These data clearly indicate that most of non-producing reserves in Daqing oilfield is in low permeable reservoirs. So the development of low permeability reservoirs is very important for the sustainable development of Daqing oilfield(Li, 1998). One of the challenges in the development of low-permeability field is that waterfloods commonly suffer from low injectivity, poor sweep, and injector-to-producer linkage. These factors tend to degrade waterflood's effectiveness and have facilitated an attempt to use enhanced recovery techniques (Hoffman et al., 2004). An important risk associated with waterflooding under fracturing conditions is that fractures lead to watering-out of wells and fast increase of watercut, with the result that injection water is cycled around rather than being used for sweeping the crude oil. The selection of a flooding pattern is important for the development effect of waterflooding. The proposed optimal waterflood pattern should(Craig et al., 1971): 1)provide desired oil production rate; 2)provide a sufficient water injection rate to support this oil production rate; 3)maximize oil recovery with minimum of water production to lift, handle and dispose of; 4)take advantage of known reservoir rock characteristics such as directional permeability, fractures, dip, etc.; 5)utilize existing wells and thus minimize drilling of new wells; 6)be compatible with the flooding patterns of operators on other leases.

Abstract This presentation discusses the results of experimental and field case studies of a remedial treatment technique designed to eliminate fracture proppant production. This process uses a low-viscosity consolidating agent, which is placed into the propped fractures via coiled tubing or conventional tubing coupled with a pressure-pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Laboratory gas flow testing indicates that the proppant pack in a fracture model under closure stress required low-strength bonds between proppant grains to withstand high production flow rates. Field case histories are also presented to discuss treatment procedures, precautions, and recommendations for implementing the treatment process. One major advantage of this new remedial treatment technique is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and their lengths, without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginally economic reserves. Introduction Many fracture-stimulated wells in the world today are subjected to curtailed production rates because of sustained proppant flowback problems. In fact, many wells are actually shut in because operators found them to be uneconomical to produce at subsequently lowered rates. Typically, production becomes restricted, such as by perforations being covered with produced proppant. The proppant produced during production often causes damage to downhole pumps and to surface equipment. In addition, repairing the equipment often results in costly downtime for the wells. Low production rates directly affect potential revenue for the operator. Frequent workovers required for cleanup or sand removal, including shut-in time, also factor into the revenue losses caused by proppant flowback or sand infill. However, the problem will return and the loss of revenue will continue unless a treatment can be found that will remediate the problem at its source and not simply clean up the wellbore. After an initial completion, it is often very difficult to conduct cost-effective remedial treatments to overcome proppant-production problems. Conventional remedial treatments are usually inadequate without some type of mechanical isolation technique. Conventional methods with a good chance of effective treatment are usually either too risky for well problems or too costly to consider for low-return reservoir conditions (or both). Resin materials have also been applied to treat proppant flowback. However, a key problem with using these materials has been the inability to achieve a uniform placement of the resin into propped fractures for the entire perforated interval. This problem is amplified by the presence of variable permeability, perforation debris, formation damage in the near-wellbore region, and the high viscosity of many resin materials. A system that attacks the problem at its source is a better approach to this problem. Using a system of treatment fluids placed precisely into propped fractures by coiled tubing can turn many marginal wells into excellent producers, and do so cost-effectively. The treatment chemicals introduced into the propped fracture will form a consolidated, highly permeable pack that can withstand the high drawdown associated with production. This paper discusses such a system.

Abstract The use of foamers to remove water from wells that are challenged by hydrostatic head pressure is common practice. The success of the process, however, is predicated on the proper selection of candidate wells, the proper selection of foaming agent, and application. Foam assisted lift does not work on all wells. At a time when resources are in short supply, dividends are returned by applying resources to candidate wells that have been thoroughly screened to improve the success rate related to foam assisted lift technology. Properly formulated foaming agents will offer better value and return on investment than marginally performing products. Comprehensive evaluation of the application is critical to achieving the desired results of a foam assisted lift program. Experience has demonstrated the importance of selection and application to the success of foaming agents. Foam assisted lift for economical production of adolescent and mature wells adds tremendous value and is a viable alternative for challenges related to liquid loading. Continuous improvement based on well changes must be considered as a significant part of the process. Adopting a comprehensive process related to a deliquification strategy will allow for extended success of foam assisted lift programs, improved production rates and revenue, and improved resource utilization related to a better return on capital and resources expended. Introduction Virtually all producing wells produce a liquid of some type - either hydrocarbon or water. For the production process to occur, liquid must be removed from the wellbore. Accumulated liquid can create a hydrostatic head pressure that impedes removal of fluid from the wellbore. As reservoir pressure declines, production rates are reduced. The production of a well will always result in a reduced reservoir pressure over the life of the well. Loading occurs on all wells. The question that must be answered for each well is "When will this well load"? Wells with low bottomhole pressure require a means of artificial lift to transfer fluid from the wellbore to surface treating equipment. Conventional methods of artificial lift are pumps (rod, hydraulic, ESP, etc.), gas lift, and plunger lift. Conventional methods of unloading wells include flaring, "blowing down", nitrogen stimulation, or "rocking". In recent years, foaming agents have been broadly applied with success as a means of artificial lift and for unloading loaded wells. Foam assisted lift (FAL) has become an integral part of extended production plans for many wells considered to be "marginal producers". Foaming agents have been used globally for removal of water from loaded wellbores for many years. Most producers think back to the days of using soap sticks to unload wells. In some areas, liquid and/or powdered detergents have also been utilized to create foam for liquid removal from a wellbore. Often, the use of soap was a part of a "last ditch effort" to get a well flowing - this was one of the "tricks of the trade" in the oil and gas industry. Recent applications indicate that FAL can not only be an integral part of mature production, it can be utilized on adolescent producers to improve production rates by returning wells to their unimpeded production potential. With gas consumption becoming an increasingly more important part of global energy supply, producers are focusing on efforts to support the demand by increasing production from all wells. This paper will address issues related to FAL that must be considered for long term success. Three steps for FAL success are: proper well diagnostic, proper foaming agent selection and proper application and assessment.

Abstract Intercampo oilfield is characterized by heavy oil with mid-high permeability and high oil saturation, which is an unconsolidated reservoir driven by edge water and bottom water. This paper presents the oilfield's application of three decline analysis models to the 13 horizontal and 13 vertical wells of the oilfield respectively, as well as the comparison of the decline features between vertical and horizontal wells. The authors point out that the decline analysis models are not only applicable for vertical wells but also for horizontal wells. Although the water cut rising of horizontal wells are different from vertical wells, the authors emphasize the well type and reservoir properties are not associated with the decline analysis models. In regards to screening and comparing of decline analysis models; how to select and use the models; their application condition; and the models features are clearly presented in this paper. The paper introduces two new decline analysis models for horizontal wells. They have been applied to predict production rate of the oilfields, reservoirs, and wells, as well as their future trends. The results accord well with the actual data from the oilfield. The classical models screened out and the new models were recommended analyzing the production performance of the oilfields and reservoirs for the types of wells. Introduction The Intercampo Oilfield, located in Zulia in the northeast part of Lake Maracaibo in Venezuela, was taken over by CNPC American Ltd. in 1998. The water depth of the lake ranges from 7 to 26 meters and the entire area is 39.56 square meters in extent. Most of the reservoirs are buried from 3560 to 7500 ft, with heavy crude-oil gravity ranging from 12.5 to 23.3 API. The reservoir is characterized by strong heterogeneity, substantial differences in physical properties, such as middle-heavy crude oil, edge water and bottom water [1]. CNPC American Ltd drilled 131 new wells, including 54 horizontal wells by the end of 2004, of which the first horizontal well was drilled in 1999. In the new wells, except for twenty seven ESP wells, 77 wells are produced by continuous gas lift. The existing decline curve analysis techniques, which included three Arps models (exponential, hyperbolic, and harmonic, 1945), and Fetkovich model (1980), are derived empirically. But the Arps models are still a preferred method for forecasting the oil production and proven reserve. The methods have played a very important role in exploration and development of oilfields in the world [2–6]. Li and Horne (2001) developed their decline analytical model, called the Li-Horne model [7–8], and based on fluid flow mechanisms study. In fact, Li and Horne made a conceptual mistake in their reasoning of the Arps models. Our research found that the Arps' models does not have any association with fluid flow mechanism, reservoir types, and the fluid's characteristics, such as steady or unsteady flow and single or multiphase flow. The two new decline analysis models are introduced in this paper; they are named the Orstrand-Weng model [2, 9] and T model [10]. By using the two models, the production decline analysis and reserve prediction both will be done. The main purpose of the paper is to conduct a comparison among the four models of the Arps model, Li-Horne model, Orstrand-Weng model and T model for the application condition and results in the oilfields. Reservoir Description In the last decade, horizontal well technology has been employed widely in the production of heavy oil and extra heavy oil in the reservoirs of the Intercampo oilfield. The reservoirs are currently classified into three types. The first type includes two areas of BASUP and BAMED. These reservoirs are situated in the upper Miocene, characterized by heavy-oil, mid-to-high permeability, and high-saturation, unconsolidated sand reservoirs. In the second type, we have BAINF, LAGNA and LGINF, in the middle Miocene. They are middle-heavy crude oil, mid-to-high permeability, high-saturation, unconsolidated sand reservoirs. Finally, the third type B-2-X features, a middle-heavy crude oil, low porosity-permeability and high-oil-saturation sand reservoir, situated in the lower Eocene.

This paper was also presented as SPE 106593 at the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference held in Buenos Aires, Argentina, 15–18 April 2007. Abstract Production of large volumes of water, coupled with production of formation sand and fines from oil and gas wells, often curtails the potential production of hydrocarbon. It is therefore highly desirable to decrease the volume of water and mitigate the solids produced from producing wells. Water and sand control generally have been addressed as separate problems with different treatment solutions. This paper discusses the development, and presents the field testing results, of a 2-step process that combines both water- and sand-control treatments into a single treatment. Laboratory experiments were performed to examine the impact of these combined treatments. The relative permeability modifier (RPM) treatment results in water permeability reduction with little or no reduction in permeability to oil. Treatment with a consolidating agent transforms the unconsolidated formation sand and/or loosely packed proppant into a cohesive, consolidated, yet highly permeable, pack. The combined process has been field tested successfully. Results from field tests have shown that this process helped reduce on average 50% of water production, effectively eliminated the production of formation sand, and allowed the wells to withstand high production flow rates. Introduction Both water production and sand production are a major concern in the petroleum industry because they are the most costly problems affecting hydrocarbon production rates. It has been shown that water production impacts the tendency of sand production.1 A recent study performed by Wu et al.2 showed that the effect of water cut on perforation failure and sand production is most significant for sandstones with high clay content. Many oil wells produce a gross effluent comprising greater than 80% by volume of water. As a result, most of the pumping energy is expended in lifting water from the well, after which, the effluent must undergo an expensive separation process to recover water-free hydrocarbons. Disposal of the remaining water is also a troublesome and expensive process. For these reasons alone, it is highly advantageous to decrease the volume of water produced from oil and gas wells. In addition, however, decreasing the flow of water into the wellbore can help lower the liquid level over the pump in the wellbore and reduce backpressure in the formation to improve pumping efficiency and net daily oil production. Another expensive byproduct that often accompanies oil and gas production is the production of formation sand and fines particulates, which is often preceded by water intrusion. Once water production begins, cementation between formation sand grains can deteriorate, allowing the formation sand and fines to migrate, or produce, with the production fluids. The higher the flow rates, the worse the problem. Fines migration often causes formation damage as pore channels or flow paths become plugged with fine particles. The wellbore can become filled with formation sand, choking off the production flow path and often requiring workovers to remove the sand fills. Formation particulates produced with production fluids can also destroy downhole and surface equipment. These unwanted byproducts of oil and gas production have typically been addressed as separate issues requiring separate treatment solutions. Water control or conformance has been addressed by numerous studies.3–6 Plastic or resins were applied in consolidation treatments for sand control starting in the 1940s.7,8 The system described in this study offers a fresh approach for attacking both water and sand production problems at their source, using a single two-step process. It provides a viable and cost-effective treatment plan for reducing water and solids that can result in significant savings in time and production cost during the life of the well. Water Control Systems The chemical systems that are suitable for reducing or controlling water production in this study are nonsealing systems. They allow the flow of fluids through a porous medium even after the treatment. These non-sealing systems are typically dilute solutions of water-soluble polymers. They reduce effective water permeability by means of a "wall effect" by polymer adsorption onto the formation,9 creating a layer of hydrated polymer along the pore throat that inhibits water flow without substantially reducing the flow of hydrocarbons (Fig. 1).