A Barnett shale water-production data set from approximately 11,000 completions was analyzed using conventional statistical techniques. Additionally, a water/hydrocarbon ratio and first-derivative diagnostic-plot technique developed elsewhere for conventional reservoirs was extended to analyze Barnett shale water-production mechanisms. To determine hidden structure in well and production data, self-organizing maps and the k-means algorithm were used to identify clusters in data. A competitive-learning-based network was used to predict the potential for continuous water production from a new well, and a feed-forward neural network was used to predict average water production for wells drilled in Denton and Parker Counties, Texas, of the Barnett shale.Using conventional techniques, we concluded that for wells of the same completion type, location is more important than time of completion or hydraulic-fracturing strategy. Liquid loading has potential to affect vertical more than horizontal wells. Different features were observed in the spreadsheet diagnostic plots for wells in the Barnett shale, and we made a subjective interpretation of these features. We find that 15% of the horizontal and vertical wells drilled in Denton County have a load-water-recovery factor greater than unity. Also, 15 and 35% of the horizontal and vertical wells drilled, respectively, in Parker County have a load-recovery factor greater than unity.The use of both self-organizing maps and the k-means algorithm showed that the data set is divided into two main clusters. The physical properties of these clusters are unknown but interpreted to represent wells with high water throughput and those with low water throughput. Expected misclassification error for the competitive-learning-based tool was approximately 10% for a data set containing both vertical and horizontal wells. The average prediction error for the neural-network tool varied between 10 and 26%, depending on well type and location.Results from this work can be used to mitigate risk of water problems in new Barnett shale wells and predict water issues in other shale plays. Engineers are provided a tool to predict potential for water production in new wells. The method used to develop this tool can be used to solve similar challenges in new and existing shale plays. IntroductionLarge bodies of data relating to fracturing operations in gas shales exist in public databases. These databases also contain production data. In this work, we first examine production figures from the Barnett shale using conventional statistical techniques to identify trends and extract meaningful information from these trends.Second, some work has been conducted on characterizing water-production mechanisms in conventional hydrocarbon reservoirs on the basis of the analysis of water/oil-ratio (WOR) and water/gas-ratio (WGR) data over time (Chan 1995). This technique has not been applied yet to understanding the water-production mechanisms in unconventional gas reservoirs. Therefore, we

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The flow behavior in nano-darcy shales neighbored by high conductivity induced natural fractures violates the assumptions behind Arps' decline models that have been successfully used in conventional reservoirs for decades. Current decline curve analysis models such as Logistic Growth Analyses, Power Law Exponential and Duong's model attempt to overcome the limitations of Arps' model. This study compares the capability of these models to match the past production of hundred shale oil wells from the Eagle Ford and investigate how the choice of residual function affects the estimate of model parameters and subsequently the well life, pressure depletion and ultimate recovery. Using the proposed residual functions increased the tendency of deterministic models to have bounded estimates of reserves. Results regarding well performance, EUR, drainage area and pressure depletion are obtained quickly and show realistic distributions supported by production hindcasts and commercial reservoir simulators. Overall, the PLE and Arps' hyperbolic models predicted the lowest/pessimistic and highest/optimistic remaining life/reserves respectively. The newly proposed residual functions were thereafter used with the Arps' hyperbolic and LGA models. We found that the use of rate-time residual functions increased the likelihood of the value of hyperbolic exponent being less than 1 by 87.5%. The proposed residual functions can be used to provide optimistic and conservative estimations of remaining reserves and remaining life using any of the above decline models for economic analysis. The key results provided by the modified DCA models help in long-term planning of operations necessary for optimal well completions and field development, accomplished in a fraction of the time currently required by other complex software and workflows.

A three dimensional geomechanical model was built using commercially available Finite Element Analysis (FEA) software to simulate propagating hydraulic fracture (HF) and its interaction with a vertical natural fracture (NF) in tight medium. The approach initially involved studying simple three dimensional single layered model followed by complex three layered model. The main area of concern was the fluid continuity at the HF-NF intersection. Different approaches were considered to model this fluid continuity. Finally, newly introduced elements were used for modeling the intersection of the NF-HF planes. These elements have ability to model the fluid continuity at HF-NF intersection. It was observed that for high stress contrast the NF activated length is smaller compared with the low stress contrast. For high stress contrast with principal horizontal stresses reversed, the HF intersects, activates and opens the NF. Increasing the injection rate results in longer and wider HF but does not significantly affect the NF activated length. Injection fluid viscosity shows an inverse relationship with HF length and a proportional relationship with HF opening or width as well as with NF length. It was observed that a weak NF plane temporarily restricts the HF propagation. On the other hand, a tougher NF or a NF with properties similar to surroundings does not show this type of restriction. The NF activated length was found maximum in the case of weaker NF and nearly zero in the case of stronger NF and NF similar to surroundings. This paper presents the results for a three layered, three dimensional geomechanical model with single HF and NF orthogonally intersecting each other, using the newly introduced cohesive elements for the first time in technical literature. Further a detailed sensitivity analysis considering the effect of stress contrast, injection rate, injection fluid viscosity and NF properties on this HF-NF interaction was conducted.

A Barnett Shale water production dataset from approximately 11,000 completions was analyzed using conventional statistical techniques. Additionally a water-hydrocarbon ratio and first derivative diagnostic plot technique developed elsewhere for conventional reservoirs was extended to analyze Barnett Shale water production mechanisms. In order to determine hidden structure in well and production data, self-organizing maps and the k-means algorithm were used to identify clusters in data. A competitive learning based network was used to predict the potential for continuous water production from a new well for and a feed-forward neural network was used to predict average water production for wells drilled in Denton and Parker Counties of the Barnett Shale.Using conventional techniques, we conclude that for wells of the same completion type, location is more important than time of completion or hydraulic fracturing strategy. Liquid loading has potential to affect vertical more than horizontal wells. Different features were observed in the spreadsheet diagnostic plots for wells in the Barnett Shale; and we make a subjective interpretation of these features. We find that 15% of the horizontal and vertical wells drilled in Denton County have a load water recovery factor greater than unity. Also, 15% / 35% of the horizontal / vertical wells drilled in Parker County have a load recovery factor of greater than unity.The use of both self organizing maps and the k-means algorithm show that the dataset is divided into two main clusters. The physical properties of these clusters are unknown but interpreted to represent wells with high water throughput and those with low water throughput. Expected misclassification error for the competitive learning based tool was approximately 10% for a dataset containing both vertical and horizontal wells. The average prediction error for the neural network tool varied between 10-26%, depending on well type and location.Results from this work can be utilized to mitigate risk of water problems in new Barnett Shale wells and predict water issues in other shale plays. Engineers are provided a tool to predict potential for water production in new wells. The methodology used to develop this tool can be used to solve similar challenges in new and existing shale plays.

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The formation of petroleum residue and deposits is a recurrent problem in low API gravity or heavy oil reservoirs and reservoirs with significant pressure and temperature fluctuations. It is also a challenge in fields where recent well interventions has pushed pipe dope into the perforations resulting in severe loss of native formation permeability and productivity. This paper discusses the application of a unique solvent acid dispersion that offers one step stimulation of reservoirs damaged with both plugging solids and organic deposits. Conventional acid systems including the numerous patented HF - HCl and organic acid blends dissolve the plugging solids and cementitious materials but cannot stimulate sandstone reservoirs damaged with organic deposits or a combination of plugging solids, fines migration and organic deposits. In fact, the formation of acid induced sludge is common. However, this acid - solvent blend dissolves asphaltene and paraffin deposits, prevents the formation of wax crystals and removes organic residue and inorganic materials simultaneously. A special surfactant train acts synergistically with the acid blend, prevents acid induced sludge and leaves the rock surfaces strongly water wet. Overall treatment efficiency was increased especially in gravel packed intervals by using a rotating jetting tool although success has also been recorded using the bullheading option. Recent experience has shown the acid blend is particularly suitable as a spearhead for injection wells. Optimum solvent loading for effective stimulation is between (10 – 20) percent depending on reservoir temperature, suspected damage mechanism and the severity of relative permeability effects. Unique experience detailing standard lab / field practice and exceptional results for several wells in the Niger Delta is the focus of this paper. Wells treated with this unique blend either as spearhead for other specialty acid systems or as a one step treatment show dramatic and sustained productivity increases of between (50 – 150) % relative to initial well data. The system has been proven to be successful in most types of completion architecture. Key technical and economic performance indicators including skin factors, production rates, specific productivity indices, payback time and treatment cost indicate this low viscosity acid blend is both technically proficient and cost effective. Introduction and Justification The in-situ remediation of damage caused by organic material deposited in the near wellbore region from well construction and intervention operations i.e. from POBM's, pipe dope, e.t.c. And from the producing system itself (waxes, resins, and asphaltenes) has historically been tackled using either one or a combination of the following measures: Hot oil - water treatments, Hot water - solvent combination, Solvent - surfactant - dispersant trains and crystal modifiers.1 The use of hot oil / water treatments is useful in the treatment of surface equipment clogged up with wax. Though these measures have attained a given degree of success even in reservoir stimulation applications, their continued usage has been proven to concentrate higher melting point carbon molecules in existing deposits, hereby making the resulting deposits more resistant to further heat treatments. This method has also been shown to cause significant formation damage by the way of negative relative permeability effects. Solvents and solvent / surfactant /dispersant trains are excellent means of organic damage removal in the reservoir. However, the extent of their organic carrying abilities is limited by temperatures below the cloud point of the organic material / solvent combination. Large quantities of solvents are typically required i.e., 100 lbs. of xylene will just dissolve 6 lbs. of C36 paraffin at 100°F.2 However, the use of the proper combination of chemicals (determined by proper lab tests) can reduce treatment volumes and costs considerably. The use of crystal modifiers or pour point depressants provide a more effective means of preventing deposits in the reservoir but are usually cost prohibitive.

In this study we have undertaken a systematic investigation of the interactive effects of the key parameters that affect the final conductivity of a propped fracture, including flow back rate, proppant loading, polymer loading in the fracture fluid, the presence or absence of breaker, closure stress, and reservoir temperature. Fracture conductivity for conditions representative of field conditions was measured using a dynamic fracture conductivity testing procedure in which a fracture fluid/proppant slurry was pumped through a fracture conductivity cell, and then shut in and closure stress applied. Water-saturated gas was flowed through the fracture for a period of time at each closure stress to mimic gas flow back during the early stages of production. In all experiments, the proppant used was 30/50 mesh ceramic proppant. We used a fractional factorial design methodology to determine the relative importance of the fracturing parameters varied. The fractional factorial design method examines the combined effects on conductivity of potentially interacting parameters, while minimizing the number of experimental runs required. The effects of the investigated factors arranged in order of decreasing impact on conductivity are closure stress, temperature, flow back rate, polymer loading, proppant concentration and presence of breaker. Increases in closure stress, flow back rate, temperature and polymer loading were observed to have deleterious effects on fracture conductivity. In particular, at high closure stresses and high temperatures, fracture conductivity was severely reduced due to the formation of a dense proppant- polymer cake. Dehydration of the residual gel in the fracture appears to cause severe damage to the proppant conductivity at higher temperatures. Also, at low proppant concentrations, there is the increased likelihood of the formation of channels resulting in high fracture conductivities.