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Well Inflow Performance Relationship (IPR) has a wide range of applications in both applied and theoretical sciences, especially in the petroleum production engineering. An accurate prediction of well IPR is very important to determine the optimum production scheme, design production equipment, and artificial lift systems. For these reasons, there is a need for a quick and reliable method for predicting oil well IPR in solution gas drive reservoirs. In this paper, back propagation network (BPN) and fuzzy logic (FL) techniques are used to predict oil well IPR in solution gas drive reservoirs. The models were developed using 207 data points collected from unpublished sources. Statistical analysis was performed to define the more reliable and accurate techniques to predict the IPR. According to the results, the new fuzzy logic well IPR model outperformed the artificial neural networks (ANN) model and the most common empirical correlations. The average absolute error, least standard deviation and highest correlation coefficient were used to evaluate the models results. The proposed fuzzy logic well inflow performance relationship model achieved an average absolute error of 1.8 %, standard deviation of 2.9% and the correlation coefficient of 0.997. The developed technique will help the production and reservoir engineers to better manage the production operation without the need for any additional equipment. It will also reduce the overall operating cost and increase the revenue.

The Marcellus Shale is a prolific source of natural gas and is located in much of the Appalachian Basin, The combination of horizontal drilling and multistage hydraulic fracturing have proven extremely successful in achieving commercial production from this ultra-low permeability formation. Even though advances in technology have unlocked considerable gas reserves, the emergence of unconventional shale formations as targets for exploration and development have created new challenges for resource development. These challenges arise because the impact many reservoir and fracture parameters have on the effectiveness of the stimulation treatments to increase reserves and improve production efficiency is not well established. The focus of this study is to identify what effect fracture half-length and well spacing have on the maximization of gas production and gas recovery efficiency from Marcellus Shale horizontal wells. A commercial reservoir simulator was used to develop a base model for the Marcellus Shale formation. These simulations models were constructed using information from the Marcellus Shale Energy and Environment Laboratory (MSEEL). MSEEL is a research collaboration between West Virginia University, Ohio State University, The National Energy Technology Laboratory, and Northeast Natural Energy. MSEEL is a long-term laboratory and field study that will assess the hydrocarbon production potential and the environmental and economic impacts of drilling and producing wells in the Marcellus Shale. The base model incorporated many of the complex reservoir characteristics that are associated with the Marcellus Shale. They include a horizontal wellbore, multi-stage fracture treatment, adsorbed gas, and in situ rock properties. Reservoir properties, such as porosity, permeability, natural fracture spacing, etc., were determine using history matching. The available data from two original horizontal Marcellus Shale gas wells at MSEEL were utilized for history matching the daily and cumulative gas production. The impact of completion parameters on gas recovery was investigated using history-matched models to evaluate the impact that fracture half-length and well spacing have on production. The predicted optimized production will be presented and compared to the baseline production results, and be presented in the paper.

The advances in hydraulic fracturing and horizontal well technology have unlocked considerable natural gas reserves contained in the shale formations. Reliable values of the shale key petrophysical properties including permeability and porosity are necessary to estimate the original gas-in-place, predict the production rates, and optimize the hydraulic fracturing treatments. The quantification of the key shale petrophysical properties however remain challenging due to complex nature of the shale foramtions. Unsteady state techniques are commonly used to estimate permeability of the shale samples because the shales typically have permeability values in nano-Darcy range. The measured permeability values by these techniques however suffer from a large margin of uncertainty and reproducibility problems. Furthermore, the unsteady state measurements cannot be performed under the reservoir stress and temperature conditions. In this study, a fully automated laboratory set-up, which has been designed and constructed for the evaluation of the ultra-low permeability petrophysical properties under the reservoir conditions, was utilized to measure the porosity and permeability of the Marcellus shale core plugs. The core plugs were obtained from a vertical well drilled specifically for the laboratory research and other scientific purposes (science well) on the site of the Marcellus Shale Energy and Environment Laboratory (MSEEL). MSEEL is a field site and dedicated laboratory in the Marcellus Shale unconventional production region of north-central West Virginia. The filed site is owned and operated by Northeast Natural Energy, LLC and contains several horizontal Marcellus Shale wells. MSEEL provides a unique opportunity to undertake field and laboratory research to advance and demonstrate new subsurface technologies and to enable surface environmental studies related to unconventional energy development. One of the core plugs obtained from the science well was used in this study for the evaluation of reliable Marcellus Shale petrophysical properties. The permeability of the core plug was measured under different gas pressures at constant net stress. The absolute permeability was then determined by applying the appropriate gas slippage correction. The porosity and the permeability of the core plug were then measured under a wide range of net stress. The measured porosity and permeability values were found to be sensitive to the stress. The permeability measurement results exhibited two distinctive behaviors with respect to the net stress that can be attributed to the natural fracture and matrix properties. The experimental results were then utilized to determine the natural fracture closure stress. The measurements also revealed that gas adsorption, when an adsorbent gas was used for the mesurements, resulted in a reduction in the absolute permeability of the sample.

The advances in hydraulic fracturing and horizontal well technology have unlocked considerable reserves of hydrocarbon contained in shale formations. However, quantification of the key shale petrophysical properties remain challenging. It is not practical to measure the permeability of the unconventional formations such as shales by standard steady state techniques because shales typically have permeability values in nano-Darcy range. Therefore, unsteady state methods have been extensively used to estimate permeability of the shale samples. However, the measured permeability values by these techniques suffer from large margin of uncertainty and reproducibility problems. These problems are attributed to the lack of consistent experimental protocols and the interpretations of the transient data. Another limitation of the unsteady-state measurements is that the experiments cannot be performed under the reservoir stress and temperature conditions. This paper provides the results of the porosity and permeability measurements on Marcellus shale core plugs which were performed using a fully automated laboratory set-up for evaluation of the ultra-low permeability petrophysical properties under the confining pressure. The permeability of the core plug were first measured under different gas pressures at constant net stress. The absolute permeability was then determined by applying the gas double-slippage correction. The porosity and the permeability of the core plug were then measured under a wide range of net stress. The measured porosity and permeability values were found to be sensitive to stress. Two distinctive behaviors with net stress, for both porosity and permeability, were observed that can be related to the natural fracture and matrix properties. The experimental results were then utilized to determine the natural fracture closure pressure. The permeability measurements with carbon dioxide revealed that permeability is impacted by adsorption. The results of the measurements with were carbon dioxide also provided information for determination of the sorption characteristics that were found to be in agreement with the published values.

The reservoir fluid properties exhibit significant deviation from their bulk properties under confinement in nanopores. As a result, storage capacity and recovery can be impacted in the shale reservoir due to nanoscale pore structure. It is therefore critical to investigate the impact of pore confinement to accurately estimate the gas resources and the phase behavior in the shale reservoirs. In this study, the shift in critical properties of the typical Marcellus Shale gas confined in different size nanopores were determined. The adjusted fluid properties was then used to estimate the gas deviation factor for dry gas and to predict the phase behavior of gas/condensate. The gas/condensate fluid model was then used in a compositional reservoir simulator in order to estimate the liquid recovery from a Marcellus Shale gas/condensate reservoir developed by hydraulically fractured horizontal well. The results indicate that the gas storage capacity of the shale is altered by the pore confinement. The degree of the fluid properties alteration by pore proximity in the shale depends on the composition of the gas mixture and the size of the nanopores. Therefore to accurately estimate the gas resources in the shale reservoirs, it is necessary to incorporate the alteration of the gas deviation factor by pore proximity. In gas/condensate shale reservoirs the fluid confinement could have either positive or negative impact on the liquid recovery depending on the pore size. The results of the investigation can provide an insight relative to production optimization and economic recovery of gas/condensate reservoirs in the unconventional resources.

During hydraulic fracturing process, the formation undergoes significant changes in the net stress as a result of the fluid injection and retrieval. These stress changes impact the formation petrophysical properties including permeability, porosity, and the compressibility. In this experimental study, the impact of geomechanical changes on shales petrophysical properties is investigated using a laboratory set-up that was designed and assembled for fast and robust shale core plug porosity and permeability measurements under steady-state conditions. This laboratory set-up is capable of accurately measuring shale core plug ultra-low permeability and porosity because it has a resolution of one millionth standard cubic centimeters per second for gas flow rate and one hundredth cubic centimeters for pore volume measurement. The laboratory set-up allows measurements to be performed under isothermal conditions by automated temperature control. The application of the confining pressure on the shale core plug allows permeability and porosity to be measured under a wide range of net stress.A sequential set of experiments were performed in this study. During the first set of experiments, the permeability of the core plug was measured by increasing the net stress from 500 psia to 7,900 psia followed by decreasing net stress from 7,900 psia to the initial net stress condition. The next three sets of experiments repeated the same steps as the first set on the same core plug. However, during the third set only the porosity, and during the fourth set only permeability was measured.The measured porosity and permeability values from the experiments clearly exhibited hysteresis with the net stress changes. The hysteresis was more pronounced for permeability than it was for porosity. Since the permeability changes were non-linear with respect to net stress changes, Walsh method was used to estimate the fracture closure pressure. The results indicate that sequential net stress changes can cause a reduction in fracture closure pressure. This reduction however tends to diminish with increasing number of sequential stress changes. Finally, comparing the porosity and permeability measurements revealed two distinctive behavioral changes for both porosity and permeability that can be contributed to the natural fracture and matrix properties.

The long-term geological sequestration of carbon dioxide (CO2) in underground formations (deep saline aquifers) is the most economically viable option to decrease the emissions of greenhouse gas in the atmosphere which are the main contributing factors for global warming. The injection of CO2 in carbonate aquifers dissolves some of the calcite rock due to the formation of carbonic acid as a result of the interaction between CO2 and brine. This rock dissolution may affect the rock integrity and in turn will affect the rock mechanical properties. The effect of CO2 on the rock mechanical properties is a key parameter to be studied to assess the aquifer performance in the process of geological sequestration and to get safe and effective long-term storage. The main objective of this study is to address the impact of geological sequestration of CO2 on the mechanical properties of carbonate aquifer and cap rocks. In addition, the effect of the storage time on these properties are investigated. Moreover, the effect of CO2 sequestration on rocks with different mechanical properties are studied, and the good candidate carbonate rocks for geologic sequestration are identified. In this study the CO2 was injected and soaked with the brine with the core at high pressure and high temperature (2000 psi and 100°C) to simulate the actual downhole conditions The carbonate cores were analyzed for mechanical properties using indirect tensile strength, unconfined compression, and acoustics testing machines. Results show that CO2 sequestration affected the mechanical properties of the carbonate rocks as well as the cap rocks. Long time soaking of CO2 in brine allowed for the formation of enough carbonic acid to react with the cores and this greatly impacted the rock mechanical and acoustic properties. The significant impact of CO2 storage was noted on Khuff limestone and the good candidate among the carbonate rocks studied here for geological sequestration of CO2 is found to be Indiana limestone.

This paper introduces a robust and accurate technique for the steady-state permeability and porosity measurements in ultra-low permeability shale core samples. A laboratory set-up was designed and assembled which has a resolution of one nano-darcy for the permeability and one-hundredth cubic centimeters for pore volume measurements. Extremely accurate differential-pressure transducers are used to measure the flow of gas passing through the core sample under in-situ conditions. The in-situ conditions are achieved by maintaining isothermal conditions and the application of the confining stress on the core sample. The laboratory set-up is fully automated to eliminate any human error and more importantly maintains the temperature stable within the enclosed unit. A series of measurements were performed on a Marcellus Shale core sample under wide range of pore and confining pressures using Helium (He) as a non-adsorbent and Nitrogen (N2) and Carbon Dioxide (CO2) as adsorbent gases. The measured gas permeability under steady-state condition is generally higher than the absolute permeability due to gas slippage (Klinkenberg 1941). Recent experimental and numerical studies indicate that permeability values for organic rich shale obtained by using different gases are much larger than the absolute permeability predicted by Klinkenberg the slippage theory. In ultra-tight formations such as organic rich shale, the measured "apparent" permeability is not a linear function of reciprocal of pressure as predicted by Klinkenberg. Thus, a new method based on the double gas slippage theory in nano-capillaries has been proposed for reliable estimation of the shale absolute permeability. In this study both Klinkenberg and double slippage corrections were applied to the steady-state permeability measurements. The results indicated that application of Klinkenberg to the permeability measurements lead to negative absolute permeability for shale samples. However, the double-slippage correction resulted in physically plausible values for absolute permeability of shale samples. Finally, the measurement results with adsorbent gases indicated that the adsorbed gas layer thickness can significantly impact the gas transport and storage in organic rich shale reservoirs and needs to be considered for hydrocarbon in place calculation and production predictions.

The long-term production behavior of horizontal wells producing from Marcellus shale due to limited production history has not been well established. As a result a simple method for predicting the long-term production and reserves would be of interest. Several production decline curve analysis models have been proposed specifically for application to unconventional gas reservoirs. However, reliable production predictions cannot be obtained when they are applied to limited production history such as those available from Marcellus shale wells. In this study, the production and completion data from a number of horizontal wells completed in Marcellus shale were collected and used to build a generic model. The model was then in conjunction with a commercial dual porosity numerical model which included the adsorbed gas to simulate long-term production profiles for Marcellus shale horizontal wells with multiple hydraulic fracture stages. The simulated production profiles were then utilized to develop correlations for adjusting the conventional (Arps) decline curve constants obtained to from the limited production history to accurately predict the long-term production performance. The impacts of key formation and fracture properties on the decline curve constants were also investigated. Finally, the correlations were utilized to accurately predict the long-term production rates from a Marcellus shale horizontal well in West Virginia based on the early production history.

The production behavior of horizontal wells producing from Marcellus shale has not been well established due to limited production history. As a result a simple method for predicting the long-term production would be of interest to the industry. Several DCA models have been proposed specifically for unconventional gas reservoirs. However, their reliability to predict the long-term production for Marcellus shale horizontal wells has not been established. In this study, production and completion data from a number of horizontal wells completed in Marcellus shale were collected. In addition, the properties of Marcellus shale were measured in laboratory with precision equipment designed for unconventional formations. The field data as well the laboratory measured properties were utilized in conjunction with a commercial numerical simulator to predict the long-term production behavior of horizontal wells producing from Marcellus shale. The numerical model allowed for inclusion of adsorbed gas, multiple hydraulic fracture stages, as well as dual porosity behavior. The predicted production profiles were then utilized to evaluate the applicability of the various DCA models. Subsequently, a technique was developed to estimate the parameters of the DCA model to predict the long-term production based on the early production history as well as the key reservoir parameters. Finally, the results of the DCA model predictions were compared to the history-matched simulation model predictions for confirmation.

The Marcellus shale formation, with more than 463 trillion cubic feet (Tcf) of recoverable gas in Pennsylvania and West Virginia, will play a critical role in providing clean energy, environmental sustainability, and increased security for our nation. However, due to recent low gas prices, most of the operating companies have slowed down their activities in dry gas areas and refocused their attention in oil and condensate production from liquid-rich regions. This change in production plans requires detailed investigation of gas condensate bank developments and saturation dynamics in shale gas reservoirs that change greatly depending on reservoir rock and fluid properties and also operating conditions. An advanced level of understanding of the parameters affecting gas condensate phase behavior is necessary in order to make accurate predictions of these changes. Phase behavior and critical properties of gas condensate in shale gas reservoirs is significantly different than that of gas condensate as bulk in the PVT cell. It is highly affected by shale pore size distribution leading to changes in gas compressibility, viscosity, formation volume and original gas in place calculations. In addition to pore size effect, fluid composition, natural and hydraulic fractures, reservoir anisotropy, rock compressibility and number of horizontal wells and their operating conditions could also significantly impact the condensate bank developments and saturation dynamics. To quantify the importance of these parameters experimental design model, i.e., Plackett-Burman, implemented following a systematic approach for two different cases (single well cylindrical model and actual Marcellus shale gas reservoir). Detailed uncertainty analysis of different parameters using Marcellus shale gas reservoir model show the significance of reservoir fluid composition, matrix anisotropy, rock compressibility and hydraulic fracture spacing on condensate bank developments where the pore size confinement effects has been ignored. They also show that gas condensation is not only a near wellbore phenomenon but it can happen deep into the reservoir causing severe formation damage. However, considering the nano-pore size characteristics of Marcellus shale gas reservoir by assuming average 2 nm pore size distribution the modified critical properties and fluid behavior, results in significant reduction in condensate saturations around the wellbore and inside the reservoir. This significantly alleviates the formation damage that has been seen in the absence of nano-pore wall confinement effects. Based on our study, critical properties and phase behavior of reservoir fluid under pore wall confinements have the most significant impact on production strategies and stimulation design for Marcellus shale gas reservoirs.

ADCO operates the oil and gas reservoirs/fields in onshore Abu Dhabi. Tight gas reservoirs are thin bedded, laminated and heterogonous carbonate reservoirs. Testing of the tight gas reservoirs in vertical wells was not justifying the completion, hence the production, mostly for economic reasons due to low and non-sustainable rate. Recently, ADCO commenced a campaign to appraise the tight gas reservoirs in the onshore operating fields. The first trial was commenced in Jan 2010. In which, the Lower Thamama; with five (5) sub-layers, thin-bedded, laminated and heterogeneous gas reservoirs were appraised. The drilling within a six (6) feet thick interval of sub-layer for almost 1000’ was really an operational challenge prior to dive the well across the dense (stylolitic) interval to drill the second thin sub-layer. The well trajectory was adapted to appraise as much sub-layers as possible aiming benefiting maximizing the reservoir contact per drainhole. The production results from the first appraisal well encouraged the team to set a development plan. The well-planning by targeting different sub-layers minimized the well interference and improved the draining areas per well. The 3D seismic interpretation, core data, log analysis and formation evaluation in addition to test data from vertical wells were the basis for the 3D reservoir modeling in order to understand the lateral heterogeneity of the reservoir hence planning the well geometry to geosteering within the developed reservoir areas. Imaging While Drilling is a real-time tool that afforded excellent well-placement practices. ADCO is enthusiastic to aggressively tackle the tight reservoir issues to produce bypassed hydrocarbons. The challenges are huge however the expectations are immense.

Producing hydrocarbon directly from the early mature source rock is becoming a subject of interest for Abu Dhabi National Oil Company (ADNOC) in recent years. The maturation modeling done in ADNOC for the Cenomanian Shilaif formation indicated the presence of early mature kitchens in the offshore and southern onshore synclines. Another maturation modeling showed that the Oxfordian Diyab Formation is also prospective mainly in the northwestern offshore area of Abu Dhabi.Several conventional stimulation attempts were made in order to produce hydrocarbon from these source rock intervals encouraged by strong hydrocarbon shows while drilling and high hydrocarbon saturation from interpreted logs. Unfortunately, no successful results were obtained during all previous trials.A volumetric calculation showed that the estimated volume of the hydrocarbon available in these new areas is significant and once a successful production method is implemented, an economical hydrocarbon recovery can be obtained.In 2011, ADNOC drilled one well in the onshore area of Abu Dhabi. A secondary objective of the well was to test productivity of Diyab source rock and for the first time in Abu Dhabi a new approach was planned and implemented to produce these source rock intervals.Due to logistical issues, the original testing design was not excuted, and a re-designed program was performed with the available equipments on site to prove the concept of producing hydrocarbon from such formations.Promising results of gas and condensate were obtained and assuming much better results if the well is drilled in the optimum potential location in the most northwestern onshore area of Abu Dhabi.In this paper, we will explain both the geological aspects of the potential Diyab source rocks in Abu Dhabi and the planned program, difficulties, executions and results of the new approached stimulation.

This paper presents the application of an integrated modeling approach to the facility design and construction stages of a mega-project for a giant oilfield offshore Abu Dhabi. The scale of the EPC task is unprecedented in the UAE and requires careful design to optimize the capital investment. In addition, the project uncertainties require that a high degree of flexibility be factored into the design process. The integrated modeling approach couples surface and subsurface flow models to achieve a complete system solution that incorporates many levels of constraints and realistically represents future behavior. This approach addresses a number of key issues. Firstly, multiple different quality reservoirs produce to a shared surface facility. Consequently, the field is highly sensitive to back pressure variation and so requires a rigorous treatment of well and surface physics. Secondly, the sub-surface uncertainties and sheer size of the investment requires a flexible approach to design, hence, many simulation scenarios are required to provide improved decision support. Finally, close collaboration is required between the sub-surface and surface teams to ensure optimization of facilities design and reservoir management for cost and recovery. The adopted methodology utilizes an integration framework which couples reservoir and topsides models into a predictive tool for development planning. This paper describes how the integrated modeling approach was utilized to provide input to design process for several aspects of the field development plan during the design and construction stages. This will include discussion of the phasing of the production facilities, requirement for temporary facilities, modular compression and separation units and the optimization of the drilling program for planned infill wells. The paper presents a best integrated modeling practice supporting facility design process which is applicable for similar scale projects, highlighting the role of integrated model as a means to foster collaboration between surface and sub-surface teams.

This paper reviews the performance of two immiscible Water Alternating Gas (WAG) pilots in W Field located in onshore Abu Dhabi- UAE. The main oil bearing reservoirs in the W Field are in the X, Y, & Z Zones. In August 2007, a gas injection pilot in Zone X was converted to a three-month cycle WAG pilot. The next month, a water injection pilot in the same zone was also converted to a three-month cycle WAG (Water Alternating Gas) pilot. The gas, water and WAG injection pilots were designed to increase sweep efficiency and optimize oil recovery from Zone X. The pilots are due to fulfill their objectives by year end 2012. Extensive monitoring programs were implemented in order to assess the performance of the pilots. These programs included frequent pressure measurements (BHCIP, PBU and PFO), production testing, cased-hole logging (RST/CNT/RPM/TDT), Flagship-PLT, PNL and Tracer injection monitoring. The results of the monitoring programs and the lessons learnt are discussed in detail. These results form the basis for the development of Zone X full field development plan. Immiscible WAG injection for 5 years showed improvement in sweep efficiency and recovery in Zone X. Field development plan considered drilling 8 WAGs wells in near future.

This paper demonstrates the value of collecting and interpreting real-time data for reservoir surveillance. We present three examples of real-time data acquisition and interpretation. The first example shows how formation pressure while drilling (FPWD) data provides permeability quantification for placement of a horizontal lateral. Initial performance of the pilot injector confirmed optimum placement of the well demonstrating value of information (VOI) from real-time data acquisition. In addition, pressure data helped in understanding the pressure distribution along the lateral due to support from a nearby gas injector and also in adjustment of mud parameters for drilling. The second example highlights the use of downhole fluid analysis (DFA) to confirm gas breakthrough detected earlier by open hole logs, to estimate gas oil ratio of the producer and help selection of fluid sampling point. Integrated analysis of logs, modular formation-dynamics tester (MDT) pressures, DFA results, flow test data and subsequent PVT analysis of oil provided indication of complex gas movement from injector to producer and provided insight on vertical sweep of gas. The third example demonstrates the use of permanent downhole gauges (PDHG) data for real-time performance monitoring of a maximum reservoir contact (MRC) well. Results of the analysis show clear evidence of voidage balance from nearby MRC injector and underscore the feasibility of field development with water injection in a lower permeability area. Combining the effective well length derived from production logging tool (PLT) data, the example also illustrates pressure /rate deconvolution analysis to determine permeability and skin. Additionally, rate-transient analysis (RTA) is done using rate and high-frequency long-term pressure data to compute permeability, skin and drainage area of the well.

In the context of global warming, CO2 capture is one of the explored solutions for greenhouse gas emission mitigation. Its injection in oil fields is one of the EOR schemes adapted to the Middle East carbonate reservoirs. A very high ultimate oil recovery is expected with such a process. A proper design to develop full field EOR CO2 is yet to be found and may be fulfilled through the implementation of one or several pilots. This study of EOR CO2 pilot implementation required a geosciences, reservoir and surface integrated work in order to place it in some robust and promising locations. A static and dynamic synthesis was performed to understand and better capture the structural context of the field and its level of production maturity. The major risks were taken into account for the selection thanks to a complete synthesis of the available data from the core scale to the surface facilities. An adequate methodology was developed to narrow down the possible locations from the field extent (several hundred km2) to only a few squared kilometers of interest. The field was divided in 6 km2 squares (called "locators") for which a two step selection process was applied. In the first step, the geological typology of the reservoirs and their dynamic statuses at the locator level were defined. Then the risks associated to CO2 injection were assessed. At the end of this step, the selected locators were the less risky ones, representating each geological typology. In the second step, the locators were studied more thoroughly with the evaluation of the level of knowledge illustrating the amount and quality of data available; a geological variability study on permeability was also performed on each area. Finally the surface constraints were incorporated to prevent any incompatibilities with the current or future facilities. This second step provided another sub-selection of locators amongst the ones kept at the end of step 1. Overall, the methodology applied allowed to screen the whole field and its reservoirs, and to identify some promising pilot locations representative of the geology, for a given dynamic status, combining high level of knowledge and low risks related to CO2 injection.

The emergence of the ultra-low permeability formations, such as Marcellus Shale, as a target of exploration and development has created new challenges for resource development. To achieve economic production from shale formations massive stimulation treatments are required. Horizontal wells are the most effective in providing access to the formation to perform multi-stage hydraulic fracturing treatments. The limited field experience with multiple hydraulic fractures in horizontal wells indicates that significant increase in initial production can be achieved as the number of hydraulic fractures is increased. However, the production performance, particularly over longer time periods, is not well established. The objective of this study was to analyze the production performance of multiply fractured horizontal well completed in Marcellus Shale to determine the long term production performance. The production history from a number of Marcellus Shale horizontal well in West Virginia were collected and analyzed using different commercial reservoir simulators. The impact of reservoir and hydraulic fracture parameters on the production performance and gas desorption were also investigated. The results indicated the presence of number of different flow regimes. The hydraulic fractures appear to dominate the early production performance while the later production is influenced by natural fractures. The results can be utilized to investigate the feasibility horizontal wells with multiple hydraulic fractures and optimize the production from the shale formation.

The interest in exploitation of ultra-low permeability formations, such as the Marcellus Shale, has increased in the recent years. Shale formations require massive stimulation treatments to achieve economic production. The recent advances in horizontal drilling and multistage hydraulic fracturing have proved successful in achieving commercial production. However, the parameters that directly affect lifetime production of the wells have not been well established. The primary objective of this study is to examine the effects of basic stimulation parameters used in hydraulic fracturing of Marcellus Shale wells on production performance. Historical production data and stimulation treatment information have been collected and analyzed for a number of horizontal wells both in West Virginia and Pennsylvania. A commercial reservoir simulator which utilizes a dual porosity model and accounts for adsorbed gas was utilized for history matching and predicting the long term production performance. The impact of the stimulation parameters including number of stages, stage spacing, the volume of water used, and the volume of sand used on production performance was investigated. An understanding of the impact of each stimulation parameter to overall production of a well can be used for the optimization of stimulation treatments.

Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves. The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs. This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.

Gas oil gravity drainage is an effective oil recovery process, which has been proven in the field. Under favorable conditions the displacement is stable and for the right surface tension combinations the residual oil saturation is low. In the absence of gas dissolution, the recovery after gas injection is usually low as a large amount of oil remains capillary trapped in the matrix blocks. However, when the main gas constitutes is soluble in the oil, the dissolution leads to mixing and interfacial tension (IFT) reduction, which cause gravity enhanced transfer between matrix and fracture. Therefore, a study of the mechanisms that control the interactions between fracture and matrix (e.g. capillarity, gravity, phase behavior and flow behavior) can help to optimize recovery. This paper concerns an experimental study to investigate whether gravity drainage is also an effective recovery process in fractured reservoirs. In this study, we describe six gas injection experiments conducted at different miscibility conditions, i.e., immiscible, developed miscible and first contact miscible (FCM), using CO2, nitrogen and flue gas. In addition, the impact of switching from an immiscible (Nitrogen, Flue gas) injection gas to non-equilibrium and fully miscible CO2 injection is investigated. In one of the experiments, we study the effect of a permeability barrier on the recovery efficiency from the matrix block when CO2 is injected in the fracture at immiscible and miscible conditions. Accurate modeling for the transfer between fracture and matrix is also essential for accurate recovery predictions. In this study, a numerical model is developed to perform compositional simulations of gas injection for different miscibility scenarios. Results revealed that ultimate oil recovery increases considerably once miscibility is reached. Miscibility can usually be achieved at high pressures only. High pressure gas injection has two disadvantages, viz., (1) one may need a larger mass of gas to fill the pore space from where the oil is recovered and (2) the density of injected gas increases significantly, which reduces the density difference between the gas and oil. This leads to less effective gravity mediated recovery. Even if the impermeable layer impairs the performance of the gas oil gravity drainage (GOGD) process for immiscible gas injection, it improves the recoveries for first contact miscible gas injection.

Naturally fractured reservoirs (NFR) have been receiving more attention than ever since the beginning of the last decade due to various reasons. The current understanding is not sufficient to achieve a favorable recovery factor, due to the lack of effective characterization and the complex dynamic nature of the fractured system. The fact that NFR are found in many countries around the globe in almost every lithology is another justification for more interest. The majority of the fractured reservoirs around the world are developed. Therefore, before proceeding into secondary or possibly tertiary recovery processes a thorough understanding must be accomplished to avoid undesirable results. The fracture characterization is the first building block in any NFR study. This study utilized well test data to detect fractures between two communicating reservoirs. The study was inspired by a real field example in which two reservoirs, separated by a thick non-reservoir formation, are in hydraulic communication with each other. A refined simulation model was constructed to predict the type of response that would be observed in such communicating reservoirs during a well test. This paper presents the result of this study, which showed a unique shape on the derivative due to the communication through fractures. The investigation was taken further to study the impact of the first and the third layer permeabilities on the observed shape of the derivative. The impact of fracture length, fracture permeability, fracture distance from the well, and the existence of multiple fractures were also investigated.

The objective of this study was to conduct a modeling study to determine the production performance of multiply fractured horizontal well completed in Shale formations and to investigate the impact of hydraulic fractures on the production performance of horizontal wells in ultra-low permeability formations. A commercial reservoir simulator was utilized to model both single and a dual porosity reservoir since both hydraulic fractures and natural fractures play significant roles in well performance of the low permeability reservoirs. The adsorbed gas component was also included in the models. The single and a dual porosity models were utilized to investigate the flow regimes for horizontal wells with multi-stages of hydraulic fracturing stimulation. History matching with actual production from Marcellus Shale wells was utilized to determine the basic model parameters. The results indicated the presence of number of different flow regimes. The hydraulic fractures appear to dominate the early production performance. The impact of reservoir and hydraulic fracture parameters on the flow regimes as well as the production performance and gas desorption were also investigated. The results can be utilized to investigate the feasibility horizontal wells with multiple hydraulic fractures and optimize the production from the shale formations.

Reservoir Rock Types of Kharaib reservoirs have been defined as an interval of rock within which the geological and petrophysical properties that effect fluid flow are consistent and predictable. Lithofacies classifications are a purely geological grouping of reservoir rocks, which have similar lithology, texture, grain size, sorting etc. Each lithofacies indicates a certain depositional environment with a distribution trend and dimension. Petrophysical groups are classified by Porosity, Permeability, Capillary Pressure and Pore throat size distribution.A Rock Type combines both these classifications by linking petrophysical properties and lithofacies as part of the reservoir rock type definition. It has been previously shown that the static rock types are not always representative of multi-phase flow behavior in the reservoir. In this paper, we will present evolution of the rock type scheme within ZADCO. We discuss criteria used to define reservoir rock types in the current unified scheme. The objective of the proposed rock type scheme is to address shortcomings identified with the previous one in use and is based on the following criteria: a) each Rock Type can be characterized by similar depositional environment and diagenetic process; b) Porosity/Permeability overlap is minimal between different rock types; c) each rock type has a typical and unique set of Pore Throat Size Distribution; and d) each rock type has similar set of Capillary Pressure/Relative Permeability curves at a given wettability.The recognized Reservoir Rock Types have been assigned to reservoir layers were built within a framework based on sequence stratigraphic concepts to ensure that the spatial 3D distribution of each rock types is predictable within a well-defined geological framework and finally to be used in history matching simulation models.

This paper presents an approach for permeability characterization of a thin, high-K dolomitized interval based on application of depositional and diagenetic concepts. The interval is 3.5 feet in average thickness and has higher permeability values than surrounding limestones. It is an important drilling target and the permeability shows significant heterogeneity vertically and laterally which impacts future well placement and completion designs of long laterals. Detailed core observations from 85 wells suggests that the intensity of dolomitization is laterally variable at an inter-well scale, but that there is a clear vertical trend of dolomite content increasing towards the middle part of the interval at each well location. The dolomitization is often concentrated within the grain-dominated facies and, in general, it leads to increased permeability. However, in some instances it can result in an intense overdolomitization yielding degraded reservoir quality. Permeability can also be improved in some areas by leaching of non-dolomitized material, particularly in the crestal area of the field. Core and petrographic observations combined with plug analysis data suggest that the dolomitized zone can be divided into three sublayers and characterized by two rock types: Dolostone with well-developed intercrystalline pores (high-K) and highly overdolomitized dolostone that occur in the middle sublayer.Calcareous dolostone characterized by weaker dolomitization and/or dissolution that are in the upper/lower sublayers. This rock type is also occasionally assigned to the middle sublayer where dolomitization is locally weak. Regression analyses of plug porosity-permeability values are characterized by one regression line for the dolostone rock type, which represent a higher permeability trend (Trend 1) that contrasts the calcareous dolostone rock type (Trend 2). The proposed fine-scale layering scheme and rock typing can be used to model the vertical and lateral petrophysical heterogeneity and permeability contrasts of the high-K dolomitized interval.

Shale makes up 75% of drilled formations and causes over 90% of wellbore instabilities. Although drilling fluids with acceptable performance in Shale have been formulated, the industry is still endeavouring to formulate an optimum inhibitive drilling fluid for the Marcellus Shale. In accordance, this research seeks to fabricate a means of reducing formation damage (permeability reduction leading to poor hydrocarbon production), stuck pipe incidences, heaving, sloughing and caving which are all due to the swelling of Smectite clay and shale. This research paper, in its infinite practicality, expounds upon the predicaments associated with swelling and dispersion of shale, the chemistry behind the swelling/dispersion of shale, justification of this research and the results obtained from laboratory work and experiments, experimental procedures performed in the formulation of an optimum inhibitive drilling fluid for the Marcelus Shale such as rheological, filtration and linear swelling experiments. Most importantly, this paper introduces a novel approach and experiment towards the development of an optimum inhibitive drilling fluid, utilizing a novel chemical in the industry: ω-α Diamino Alkanes (Diamino Butane and Diamino Hexane) as well as comparing the inhibitive capability of two familiar chemicals in the industry in conjunction with Chlorides and Hydroxides of numerous Alkali metals, Alkaline earth metals and Transition metals (K+, Na+, Ca2+, Mg2+, Li+ etc) in various concentrations. The rheological, shale inhibition and filtration effects of the aforementioned Hydroxide and Chloride chemicals were tested and examined which led to the subsequent elimination and selection of certain fluids which this research has recommended for testing in Marcellus Shale formations in West Virginia and similar shales in the globe. Universally acceptable filtrate loss correlations have been formulated, during the course of this research, for various base drilling fluids. Finally, it was observed that a drilling fluid system comprising of KCl, Diamino Hexane and Bentonite was effective in reducing shale and Smectite swelling when compared to the currently leading inhibitive mud currently used in drilling shale formations. This research project was limited to the Marcellus Shale formation in the State of West Virginia and the results obtained from the inhibition/swelling tests may not be universally acceptable in the evaluation of other shale formations. However, the generated rheological and filtrate loss results and correlations may be universally applied.

This paper summarizes the results of the modeling studies to determine the production performance of multiply fractured horizontal well completed in tight sand or Shale formations. A commercial reservoir simulator was utilized to model both single and a dual porosity reservoir with multiple layers. The results were utilized to investigate the flow regimes for horizontal wells with one or multi-stages of hydraulic fracturing stimulation. The impact of reservoir and fracture parameters on the flow regimes and the production performance was also investigated.

Sequestration of CO2 in depleted gas condensate reservoir has several advantages including enhanced hydrocarbon liquid recovery. Depleted gas condensate reservoirs have 13 times higher capacity than saline aquifers for CO2 storage. The injection of CO2 vaporizes the liquid that has been trapped in gas condensate reservoirs during the depletion process. This results in an increase in the pore space for storage purposes as well as enhanced economics due to additional liquid recovery. The improvements in liquid recovery will depend on purity of CO2. A compositional reservoir simulator was utilized in this study to investigate the impact of reservoir characteristics including permeability, porosity, heterogeneity, pressure, and temperature on CO2 distribution and interaction with hydrocarbons in the gas/condensate reservoirs. The results have utilized to study CO2 storage and improved liquid recovery.

This study focuses on how the fracturing treatment design parameters such as the volumes of liquid injected, size and amount of proppant influence the Estimated Ultimate Recovery (EUR), in Upper Devonian formations in the Appalachian Basin. An extensive database containing completion, stimulation, and production data from the Benson formation was utilized in this study. The selection criteria for wells which were ultimately used in the study included wells with single zone completion and long production history with adequate completion data. These criteria eliminated the major uncertainty caused by multiple zone completions or inconsistent production data. The total proppant placed during stimulation treatments was found to be the major variable that influenced EUR. Increasing the total proppant not only increases EUR but also to decreases the number of wells required to effectively drain the reservoir. Subsequent economic analysis provided the basic guidelines to achieve economic recovery from the Upper Devonian formations in the Appalachian Basin.

Skin factor is commonly used as well flow efficiency indicator and the criterion for performing stimulation treatment to enhance well productivity. Skin factor, which is generally determined from interpretation of pressure transient well tests, is a composite factor and must be broken down into its various components in order to estimate near-wellbore damage. This is particularly important in the gas wells because they experience additional pressure drop near the wellbore due to high gas velocity. This additional pressure drop near the wellbore is generally referred to as non-Darcy effect and can be approximated by a rate-dependent skin factor. Therefore, the total skin factor obtained from a gas well pressure transient test has two primary components, rate-independent and rate-dependent skins. The rate-independent skin is primarily a function of formation damage, well deviation, completion, and perforation. Rate-dependent skin accounts for the non-Darcy effects. Both of these skins can be determined directly from the interpretation of pressure transient well tests if several transient tests at different rates were conducted. The multi-rate tests are however cumbersome to conduct and it is advantageous to estimate the rate-independent skin factor from a single rate test. In order to obtain a reliable value for the rate-independent skin from a single-rate test, the rate-dependent skin must be evaluated independently. The rate-dependent skin depends, among other parameters, on the coefficient of inertial resistance, β. A number of correlations relating β to permeability are available in the literature. These published correlations are derived from limited set of laboratory measurements on various porous media. Our previous investigations have revealed that these correlations do not provide consistent results. Alternatively, β can be determined from the results of the multi-rate well tests. The calculated β values from such tests reflect the actual field conditions that cannot be replicated in the laboratory. However, the complex dependency of β on the properties of the porous media precludes development of a single β -k correlation that can provide accurate and consistent results in all reservoirs. A more realistic approach would be to develop a relation between permeability and β for a specific porous media. To develop a correlation for β, a database of multi-rate gas well tests was established which contained data from over 100 well tests obtained from a number of operators in the Appalacian Basin. The well tests from several wells in the same reservoir were available and several field-specific correlations for β were developed. The comparison of skin factor determined from these correlations against the skin factors determined from the well test data indicated that reservoir-specific correlations for β provide accurate and consistent results.

In spite of continued improvements in logging technology, mud-filtrate invasion and related formation damage due to drilling fluids can result in the misinterpreted values of rock and fluid properties in the reservoir. Well planning with accurate information of target reservoir would not only optimize drilling operation and completion but also maximizes production of oil and gas. To produce hydrocarbons effectively, the wellbore must communicate with formations beyond the altered zone and this can be accomplished by using proper perforation penetration or creating fractures. Thus the prediction of invaded zone is critical and a numerical model can be used for preplanning purposes. In this study, the dynamic filtration process and the related penetration into the gas and oil bearing reservoirs are studied in a vertical openhole system using a Computational Fluid Dynamics (CFD) software package. The radius of filtrate invasion is determined by the unsteady-state three-dimensional multiphase fluid flow model. This study investigates the communication between fluids and formations during drilling with special emphasis on the effects of formation porosity and permeability, time, and overbalanced pressure. As drilling fluids Non-Newtonians such as Bingham plastic, Power-law, and Herschel-Bulkley fluids also considered in addition to Newtonian fluids. Mud filtrate invasion in multi-layer reservoirs model and effect of hydraulic fracturing operations are also investigated in this study. The results provided an insight in the formation damage around wellbore and related reduction in the hydrocarbon flow due to altered fluid saturations. Accurate prediction of damaged zone around the wellbore will benefit different operations such as drilling fluids design, log interpretation, hydraulic fracturing and well completion.

This reference is for an abstract only. A full paper was not submitted for this conference. Plynomorph constituents and their maturation, rock oval pyrolysis, total organic carbon (TOC) analysis are carried on for the whole succession of the Upper Jurassic and the Cretaceous Formations of Iraq. These lines of analysis have been used in this study to evaluate correlation between oil of Khasib reservoir rocks and kerogen of the source rocks as well as suggestions for oil traps along the predicted migration path in East Baghdad oil Field. The gas chromatography of these oils can show biomarkers of abundant ranges to suggest mainly liquid oil constituents of parafinic hydrocarbons in the reservoir as well as low non aromatic C15+ peaks to indicate their degradation and water washing. Oil biomarkers and CPI=1.5 could indicate anoxic marine environment with carbonate deposition of early Cretaceous source. The recorded palynomorph constituents in this oil and associated water could indicate affinity to the Lower Cretaceous Chiagara and Ratawi Formations. The recorded palynomorphs from the reservoired oil are comparable to the mature palynomorphs of Chiagara and Lower part of Ratawi Formations that had generated hydrocarbons according their TOC, high hydrogen potential, mature kerogen type II and palynofacies of high generating potential for oil, while the palynomorphs of the rocks of Khasib Formation are not generated hydrocarbons. But, this last formation could be considered as oil reservoir only. Accordingly, these palynomorphs have been included in this oil during its generation from the Kerogen source of the Chiagara and Ratawi Formations, and hence been migrated within the liquid hydrocarbnos to the Khasib Formation through fractured fault passageway shown on the seismic section in Baghdad Oil Field. The increasing Pristane/ Phytane ratios to more than one, increasing migration index up to 0.9 and microfractare of the source rocks could confirm their migration.

A gas condensate reservoir in the Appalachian Basin has been converted into a gas storage reservoir. Te results of the first storage cycle are presented. When gas is injected into a depleted gas condensate reservoir, the remaining condensate will evaporate and enrich the injected gas. The degree of mixing among the residue gas, residue liquid, and the injected gas will determine the composition of the gas in the reservoir and the liquid yield at the surface when the gas is withdrawn. The results of the first storage cycle clearly indicated that complete mixing was not achieved in the reservoir. The storage gas compositional changes, due to partial mixing with the native fluids, have both positive and negative impact on the operation of storage field. The lower liquid yields reduce the requirements for liquid handling. However, the heavier hydrocarbons remain in the reservoir longer and the liquid production is extended to a greater number of storage cycles. The liquid yields were low initially because the withdrawn gas had been in the reservoir for a short period of time. Furthermore, this gas did not come into contact with significant liquid due to liquid evaporation. The liquid yields subsequently increased up to a maximum before they declined again. The decline in liquid yields was caused by retrograde condensation in the reservoir. The storage gas compositional changes reduced the storage capacity by 12 percent. The reduction in gas capacity was economically advantageous since it reduced the base gas requirements. Finally, the results of first storage cycles were utilized to optimize the liquid recovery at the surface facilities for the subsequent cycles to prevent liquid drop out by retrograde condensation in the pipeline.

Increased demand for energy resulted in the expansion of drilling activities worldwide. Any improvement in terms of well planning and drilling operation can result in significant savings for the operator. A good plan includes all information from offset wells as well as sound engineering principles and it relies on subsurface characteristics and operating conditions. While formation properties are not controlled by drilling, the operational parameters can be modified to improve the drilling operation on a real time basis. Thus it is important to study the operational factors affecting the performance of a rig. Particularly, understanding the parameters that control wellbore cleaning is beneficial in both horizontal and deviated wells.In this study, a section of casing-drill pipe annulus section was simulated using Computational Fluid Dynamics (CFD) to determine the effects of different parameters such as fluid velocity, cutting size, rate of penetration, drill pipe rotation and inclination angle in deviated wells. The simulations were conducted at steady state and the results for maximum cutting concentrations in the annulus were analyzed. Formation of cutting beds is noticed near the entry section of the annulus and the transport of the cuttings in the annular section occurred in the form of stratified flow. Fluid flow rate, angle of inclination and rate of penetration have a major impact on cutting concentrations and proper prediction of these parameters are important to avoid formation of cutting beds. It is also noted that drillpipe rotation can enhance cutting transport but it generally has a greater effect on smaller sized particles.

Multi-rate tests generally provide accurate values for gas reservoir formation parameters and deliverability equation coefficients. This type of results enables the engineer to make proper decisions on whether remedial work is required and the potential improvement that can be achieved. The multi-rate tests, such as isochronal or modified isochronal tests, are however cumbersome to conduct due to need for achieving stabilization or lengthy shut-in periods. The goal of this study has been to develop a simple and reliable method for gas well deliverability determination based on a single rate build-up or fall-off test. Traditionally, single rate tests have been analyzed using empirical backpressure equation using an average value for the exponent (n). Such approximations often provide inaccurate results and do not reveal any information regarding the conditions of the well. Alternatively, single rate tests can be analyzed using theoretical transient gas flow solutions. However, to accurately estimate mechanical skin factor and the deliverability equation coefficients from a single rate test, turbulence factor, β, must be available. There are numerous correlations in the literature for estimating β. These correlations do not provide unique results and calculated skin factor can range widely as a result. This study introduces the concept of the reservoir-specific β-factor. The methodology for developing a correlation for β factor using multi-rate tests has been developed. Once the β-factor correlation for a reservoir is established, there would be no need for additional multi-rate tests and single rate can be analyzed to provide accurate estimates of mechanical skin factor and deliverability equation coefficients. The accuracy of the proposed methodology has been verified through application in two separate reservoirs in the Appalachian Basin.

A depleted gas condensate reservoir in the Appalachian Basin has been under investigation for possible conversion to a gas storage reservoir. When depleted gas condensate reservoirs are used for gas storage, the injected gas will pressurize the reservoir and will evaporate the retrograde condensate that is remaining in the reservoir upon completion of the primary production. This will result in significant compositional alteration of the withdrawn gas from the storage. The produced gas during withdrawal cycle must be processed to remove condensible hydrocarbons prior to pipeline transportation to prevent liquid drop out by retrograde condensation in the pipeline. The composition of produced gas will depend on the degree of mixing between the injected and the residue fluids. To investigate the impact of the formation on the mixing, a compositional reservoir simulator was utilized in this study. The primary production history of the reservoir was first modeled with simulator using available data and the results of the data analysis. The phase behavior studies with Peng-Robinson equation of state (PR-EOS) provided a reliable estimate for reservoir fluid composition. Upon successfully history matching the primary production, the reservoir model was utilized to predict the composition of the withdrawn gas from the storage. Pipeline gas was injected into the reservoir and the reservoir was pressurized to its original pressure. Both vertical and horizontal wells were considered for injection to evaluate the extent of mixing among residue gas, residue condensate, and the injected gas. Subsequently, a withdrawal cycle was simulated to predict the liquid yields and gas heating contents based on the design of the surface facilities. The results of simulation study were then used to finalize the design storage field and surface facilities. The preliminary data collected after pressurizing the reservoir confirms the simulation results.

Petroleum storage tank bottom repair is a HSE Critical Activity as it posses imminent danger of fire and explosion due to entrapped crude oil or its products beneath the tank bottom as the tank bottom always susceptible to the leakage caused by corrosion. Oil industries are using various methods for its repair depending on various situations of the corroded tank bottom. At TAKREER the tank bottom is repaired with a special technique using Inert gas as continuous purge gas / blanketing beneath the tank bottom plate and adequate ventilation in the tank which is cost effective and safe practice achieved after chronological improvements.

In the past decades several hundred stimulation procedures have been performed in the Golden Trend fields of Oklahoma. The outcome of these stimulation jobs have not been the same for all wells. The effectiveness of the stimulation is a function of several factors including reservoir quality, completion and stimulation techniques. Completion and stimulation techniques can be further itemized as completion type such as open hole versus cased hole, type and amount of fluids and proppant and the rate at which they are pumped into the formation. This project was supported by DOE and GTI in connection with the DOE’s Preferred Upstream Management Practices (PUMP) project. The project was implemented in three fields in the Golden Trend in Oklahoma. Detailed production and completion data analyses revealed that the most influential controllable parameter effecting the production rate and ultimate recovery was fracture stimulation, and as such, the bulk of efforts were focused on determination of optimized hydraulic fracturing procedure. Detail stimulation data from more than 230 wells in the Golden Trend fields of Oklahoma operated by three independent operators were collected and analyzed using a new best practices analysis methodology. The study was performed for gas and oil bearing formations. Among the findings of this comprehensive study were the best stimulation practices in carbonate formations that are primarily gas producing, and clastic formations, from which both oil and gas are produced. During his study authors were able to identify the best type of fluid, the most optimal injection rate and proppant concentration for both types of formations. In this paper application of a new methodology that was used to perform the best practices analysis on the Golden Trend fields of Oklahoma is presented. CONCLUSIONS Wells in the Golden Trend are completed in several formations. The formations that are present in almost all of the wells can be divided into two major categories, clastic (oil & gas production) and carbonate (only gas production). Calstic and carbonate formations in the Golden Trend respond positively to different types of hydraulic fractures. Therefore, it is highly recommended that the clastic and carbonate formations be isolated prior to stimulation jobs in order to achieve the best results. It was identified that the recommended main fracturing fluid for the clastic formations in the Golden Trend is “Diesel Oil”. This seem to be due to the presence of certain amount of clay that is contributing to damage of the reservoir near the well bore by developing hydration spheres, a process that seem to be reversible as long as the water saturation in the reservoir is not at irreducible saturation. On the other hand it was identified that “acid fracs” and not “acid jobs” are the stimulations that should be performed in these formations. It was identified that a relatively low number of perforations (may be less than or equal to one shot per foot of pay thickness) would be the most appropriate practice of completion for wells in the Golden Trend. This seems to be true for both clastic and carbonate formations. It was identified that higher proppant concentrations work better in the Golden Trend. The recommendation is to use proppant concentrations of higher than 1.0 lbs/gal/ft. It is recommended to use average injection rates of less than or equal to 0.2 BMP per foot of pay thickness while stimulating the formations in the Golden Trend. METHODOLOGY Intelligent Best Practices Analysis (IBPA) is a two-step process. It is consisted of descriptive and a predictive analysis. During the descriptive analysis the productivity of the wells in the database is divided into several fuzzy sets and fuzzy-averages of several parameters are then calculated to identify the trends that are present in the database. These trends and patterns usually provide a pretty strong foundation for the best practices that are ultimately identified, as shown in the figures above. SPE 95942 2005 SPE Annual Conference, Dallas, Texas Intelligent Best Practices Flow Chart. Predictive best practices analysis is a drill-down process where we start with the full field analysis and end with individual well analysis. During the full field analysis we identify the best practices based on all the wells in the database. We then divide wells into groups, based on different criteria, and look at each group more closely and either, verify, refine or dispute the best practices that were identified during full field analysis. The last step of the predictive analysis is working with individual wells and using the results of past two steps as a guide to enhance the production of an individual well. We showed that although the best practices that were identified during the full field and groups of wells analysis would work for most of the wells (since that is how they were identified), there will be wells in the database (or new wells) that would not necessarily follow the identified trends as expected. This makes refining of the design by individual analysis a highly recommended exercise. The predictive analysis is based on a neural network model that is developed from the data available in the database. Figures on left and the next column highlights the identification of best practices in the Golden Trend. In the case where each record in the database represents a well in a field (as the case in this application) the classification of the wells can be based on any predetermined classifier such as well quality, operating company, well locations, geology, reservoirs involved, or any other classification that makes sense. In cases that such native (natural) classifier is not present in the database, k-mean clustering or fuzzy c-mean clustering can be used in order to cluster the records in the database. For this study wells were once grouped base on their quality, and once based on the operator. Three operators had participated in this study. Upon completion of the full field analysis the wells in the database are classified and the process is repeated for each class (category or cluster) of the wells. The classification can be based on several criteria. If there is a class indicator in the database (natural or native classifier) it can be used as the basis for the classification. The analysis (in all cases) is performed for single parameters and for multiple parameters in a combinatorial fashion as shown in these figures. The recommendation matrix at the top of this column is then generated. All the recommendations that are the results of the analysis is presented in the recommendation matrix.

Prediction and analysis of the coalbed methane (CBM) production is challenging especially at the early stages of the recovery when production is subject to two-phase flow conditions. CBM reservoirs are dual-porosity systems that are characterized by a complex interaction of coal matrix and cleat system that are coupled through desorption process. As a result, the conventional methods cannot be utilized to predict CBM production. Currently, only numerical models (simulators) can be used to predict (CBM) production behavior since they incorporate the unique flow and storage characteristics of CBM reservoirs. Often, the number of variables needed for evaluation of a given prospect is greater than that typically measured. In such cases, parametric studies are conducted to evaluate the impacts of reservoir properties on recovery factor, well performance, and future revenues. However, parametric studies with a reservoir simulator is cumbersome, time consuming and expensive. Therefore, there is a need for scientific, user-friendly tools that can assist the typical gas producers in evaluation of CBM prospects. This study presents a set of production type curves for CBM reservoirs. A reservoir model that incorporates the unique flow and storage characteristics of CBM reservoirs was employed to generate the type curves. Our previous study (SPE 91482) introduced a new set of dimensionless groups that led to development of unique set of type curves. The impact of basic reservoir characteristics was also investigated to confirm the uniqueness of the type curves. This study investigates the impact of key parameters including isotherm constants and relative permeability data on the type curves. The type curves can be used to predict and/or analyze gas and water the production from CBM wells both during de-watering and stable gas production phases. The issues concerning the application and limitation of the type curves are also presented. Finally, a type curves-based simple yet reliable tool with graphical user interface (GUI) was developed. This tool can be used for predicting and analyzing production performance of CBM reservoirs with simple and straight forward input requirements. This tool is particularly useful for parametric studies to evaluate CBM prospects.

ABSTRACT A methodology to generate synthetic wireline logs is presented. Synthetic logs can help analyze the reservoir properties in areas where the set of logs that are necessary, are absent or incomplete. The approach presented involves the use of Artificial Neural Networks as the main tool, in conjunction with data obtained from conventional wireline logs. Implementation of this approach aims to reduce costs to companies. Development of the neural network model was completed using Generalized Regression Neural Network, and wireline logs from four wells that included gamma ray, density, neutron, and resistivity logs. Synthetic logs were generated through two different exercises. Exercise one involved all four wells for training, calibration and verification process. The second exercise used three wells for training and calibration and the fourth well was used for verification. In order to demonstrate the robustness of the methodology, three different combinations of inputs/outputs were chosen to train the network. In combination "A" the resistivity log was the output and density, gamma ray, and neutron logs, and the coordinates and depths (XYZ) the inputs. In combination "B" the density log was output and the resistivity, the gamma ray, and the neutron logs, and XYZ were the inputs, and in combination "C" the neutron log was the output and the resistivity, the gamma ray, and the density logs, and XYZ were the inputs. After development of the neural network model, synthetic logs with a reasonable degree of accuracy were generated. Results indicate that the best performance was obtained for combination "A" of inputs and outputs, then for combination "C", and finally for combination "B". In addition, it was determined that accuracy of synthetic logs is favored by interpolation of data. As an important conclusion, it was demonstrated that quality of the data plays a very important role in developing a neural network model. INTRODUCTION Well logging has been in use for almost one century as an essential tool for determination of potential production in hydrocarbon reservoirs. Log analysts interpret the data from the log in order to determine the petrophysical parameters of the well. However, for economical reasons, companies do not always posses all the logs that are required to determine reservoir characteristics. This paper presents amethodology that can help to solve the aforementioned problem by generating synthetic wireline logs for those locations where the set of logs that are necessary to analyze the reservoir properties, are absent or are not complete. The intention of the technique used here is not to eliminate well logging in a field but it meant to become a tool for reducing costs for companies whenever logging proves to be insufficient and/or difficult to obtain. This technique in addition, can provide a guide for quality control during the logging process, by prediction of the response of the log before the log is acquired. The approach presented involves the use of artificial neural networks, as the main tool, in conjunction with data obtained from conventional wireline logs.

As the interest in coalbed methane production increases more and more engineers and scientists are becoming interested in the reservoir and sorption characteristics of different coal seams throughout the U.S and the world. As they set out to search for such information it becomes clear that finding such information is not easy. The difficulties associated with collecting such information are due to three major factors. First is the fact that development of CBM reservoirs is a relatively new phenomenon when it is compared with conventional hydrocarbon reservoirs. Secondly, companies that are in possession of such data and information are very protective of their data. They consider them company assets and are not ready to release them. Thirdly, whatever data and information that is available in the public domain is scattered in hundreds of technical papers and publicly funded project reports. The objective of this paper is to introduce and describe the details of a series of newly developed databases that will soon become publicly available. These databases are a collection of all the publicly available CBM related data and information in one location. This series includes three major databases. First is a literature database that includes the title, authors, topics and summary of all the available technical papers and project reports related to CBM. Each entry includes a summary of the paper and other information that facilitate locating the article or the report. The database includes papers from SPE and CBM conferences and symposiums along with reports published by DOE, GRI and others. The second database is a collection of reservoir and sorption characteristics of CBM reservoirs that has appeared in the public domain. The data has been organized by basin and field and one can identify ranges and statistics about the available data based on each basin. A reference for each piece of data is also presented. The third database is CBM well productions from different states and different local databases that has been gathered and compiled in one location for easy access. These databases are located and maintained at the Petroleum & Natural Gas Engineering department at West Virginia University.

Coalbed Methane (CBM) currently accounts for nearly 8 percent of U.S. annual gas production and approximately 12 percent of estimated total U.S. natural gas reserves. Coalbed methane proven reserves in the United States have increased from 3.7 Tcf in 1989 to 18.5 Tcf in 2002. This number is expected to increase even further as more resources are discovered and a better understanding of the existing resources is achieved. Appalachian Basin accounts about 10 percent of U.S. CBM resources. However, CBM production is very limited in the Appalachian Basin. The contribution of CBM to overall mix of natural gas sources in U.S. is expected to increase for next two decades. However, this cannot be achieved without substantial increase in CBM production in the Appalachian Basin. The problems causing the lag in development of CBM in the Appalachian Basin need to be overcome for CBM to reach its true potential in the U.S. energy equation. Gas production from CBM reservoirs is governed by complex interaction of single-phase gas diffusion through micro-pore system (primary porosity) and two-phase gas and water flow through cleat system (secondary porosity) that are coupled through desorption process. In order to effectively evaluate CBM resources, it necessary to utilize reservoir models that incorporate the unique flow and storage characteristics of CBM reservoirs. These models are often complicated to use, expensive, and time consuming. The typical gas producers in the Appalachian Basin suffer from the lack of scientific, user-friendly tools that can assist them in development of CBM resources. Therefore, it is necessary to develop tools that make it possible for typical (small to medium size) producers to seriously consider this important resource. This study presents a set of production type curves that would help the producers to predict the production from their CBM wells. As a consequence, the producers would be able to make better, more informed decisions regarding the CBM resources in the region. A reservoir model that incorporates the unique flow and storage characteristics of Coalbed Methane reservoirs was employed in this study to develop the type curves. The type curves provide a reliable tool to predict the production performance of CBM reservoirs both during dewatering and stable gas production phases. The application and issues concerning the production performance of CBM reservoirs are also discussed.