A key characteristic in unconventional reservoirs development is that they need massive hydraulic fracturing to create high permeability conduits to connect the reservoir to the wellbore and assure appropriate flow rates to make the development economical. In general, production performance for this type of reservoirs show an early high inflow followed by a steep decline. Refracture jobs have been a common practice to mitigate the flow rate decline and revitalize wells productivity.In this paper, a wide range of possible refrac configurations are evaluated using synthetic models. Parameters such as fracture spacing, matrix permeability, fracture conductivity, fracture orientation and refrac locations were varied to study their impact on the success of the refrac job. Results showed significant impact on both the overall productivity, recovery and the economic value. The results show the impact of refracturing in higher permeability cases (greater than micro Darcy) is not as economical as in the low permeability scenarios (less than micro Darcy). Results also show a possible threshold in fracture spacing (60 -80 ft between clusters) below which refracturing may not an economical completion strategy. In scenarios where the initial fracture conductivity is severely degraded, refrac can be an alternative to improve the net present value (NPV) and estimated ultimate recovery (EUR). Under the conditions of this study, fracture re-orientation cases show improvement in recovery factor (RF) but does not have a significant impact on the overall NPV. The timing of refrac has a large impact on both the NPV and recovery for the wells. In all cases, NPV was used to define optimal condition for each scenario evaluated.All cases presented demonstrate potential impact of refracturing for a typical range of properties in shale reservoirs. The results shown in the paper could be used as a catalogue for better decision support to estimate the impact of refracturing in field cases under similar configurations to determine whether refrac will beneficial.

There is a general concern in the oil industry regarding the flow of crudes at temperatures below the pour point. However, this concern is not valid as long as adequate pressure is available to maintain the continuous flow. Practically, pumping of waxy crudes below the pour point is quite common for the transportation of such crudes. Multiphase waxy crude is associated with dissolved and free gas; water can be present either as free water or in emulsion form; and gas-liquid flow pattern such as slug flow may occur with turbulent mixing. All these tend to decrease the congealing of the waxy crudes. An analysis of a case history has been carried out on the possibility of congealing of high waxy multiphase flow lines considering above governing parameters. The analysis includes normal operating condition as well as shut down and start up of the pipeline. The analysis confirmed that the congealing of crude in pipeline should not be concluded simply based on the pour point of the dead crude. This is even more relevant in the case of multiphase transportation. Based on the recommendations for the present case, a marginal offshore field of India was put on production and is producing since then without any major problem. This has eliminated a recurring cost of US $ 0.4 million per year on chemical treatment apart from capital cost on other requirements of chemical dosing. Introduction Control of paraffin deposition and pour point reduction are some of the major transportation tasks in high wax high pour point crude. Estimates (1969) showed that paraffin deposition control alone costed U.S. about US $ 5.0 million annually and Indian oil industry at present incurs over US $ 15 to 20 million equivalent annually. The problem, therefore, is long standing in crude oil transportation and continues to attract research and development in this area even today. It is of particular importance after a prolonged shutdown mainly due to difficulties in restarting of flow. Several studies have been carried out in the past relating to the problem of wax deposition and build-up and rheology of high waxy high pour point crude. The phenomenon of cooling is recognised as a major controlling factor in paraffin deposition involving precipitation of paraffinic wax and its concentration in the deposit. The prediction of pipeline temperature therefore, is basic and primary information that influences the paraffin deposition. Flow rate, flow velocity and the presence of gas and water are other important parameters which influence the crude congealing, since the mechanics of flow ceasure is also influenced both by dynamics of flow and presence of gas phase and water in the crude oil. A review of all these parameters along with one Indian case history is presented in this paper. Wax Deposition Problem In the broadest sense, wax problem in oil producing wells and pipelines is predominantly organic deposition which reduces the flow area and consequently hampers oil production. Subsequent pigging becomes difficult. Further, handling of large volume of wax and debris during subsequent pigging at processing facility is far more difficult. It is therefore logical to ascertain (i) Chemical constituents, (ii) Solubility behaviour, and (iii) Rate and nature of these organic deposits. The paraffin deposits are organic compounds, insoluble in crude at producing conditions. These compounds include -Aliphatic hydrocarbons (paraffins) both straight and branched chains,Aromatic hydrocarbons,Naphthenes andResins and Asphaltenes. In general, wax contains largely paraffins with smaller amount of naphthenes and aromatics.

The Eagle Ford Shale (EFS) is the largest single economic development in the history of the state of Texas and ranks as the largest oil & gas development in the world based on capital invested. Between 2008 and the present, the EFS has become one of the most heavily drilled rock units in the United States and is the most active shale play in the world. This paper presents a completion optimization framework for unconventional plays. The framework utilizes well production performance analysis to estimate the fracture characteristics and assists in diagnosing potential low productivity issues. The framework enables pre-completion planning, real time completion operations monitoring and post-completion evaluation to evaluate design effectiveness and optimize future design. The key components of the framework are Prospectivity Analysis, Completions Optimization and Well Performance Analysis. Prospectivity analysis provides the map of Reservoir Quality (RQ) and Rock Quality (RkQ) across the play. Pre-completion planning, a component of Completions Optimization, is driven by Prospectivity Analysis with the goal to design the best completion based on the Rock Quality data available. During completions monitoring, the designs are updated based on actual field pump rates and quantities of proppant pumped to estimate actual hydraulic and propped fracture characteristics. The effective fracture geometry is determined based on well production calibration. Wellbore and completion problems could be diagnosed in this analysis, including damage of fractures, fluid behavior, and well interference. We applied this framework to wells completed in the Eagle Ford Shale. The Reservoir Quality variability is based on petrophysical evaluation of logs acquired on all study wells. The characteristics of propped fractures were estimated based on geomechanical modeling of actual field pumping measurements. Even though the fractures extended above and below the target interval of Eagle Ford Shale, they were successful in creating the desired half-length from a design aspect. It was also observed that not all the clusters matured because of the stress shadow effect. The produced fluids in these wells ranged from black oil to gas condensate. Well interference was observed as a production penalty factor in well performance analysis. The behavior of current wells was used to design optimal completion for wells planned to be completed. This framework utilizes common data sets collected by majority of operators. It provides intelligence for completion optimization of future wells after thorough investigation into fracture design, completion operation, and effective fracture characteristics. It is a systematic approach to optimized single well design as well as field development (multiple wells, pad drilling).

Summary The Eagle Ford shale (EFS) is the largest single economic development in the history of the state of Texas and ranks as the largest oil and gas development in the world on the basis of capital invested. Between 2008 and the present, the EFS has become one of the most heavily drilled rock units in the US and is the most-active shale play in the world. This paper presents a completion-optimization framework for unconventional plays. The framework uses well-production performance analysis to estimate the fracture characteristics, and assists in diagnosing potential low-productivity issues. The framework enables precompletion planning, real-time completion operations monitoring, and post-completion evaluation of the design effectiveness, and it optimizes future designs. The key components of the framework are prospectivity analysis, completions optimization, and well-performance analysis. Prospectivity analysis provides the map of reservoir quality and rock quality across the play. Precompletion planning, a component of completions optimization, is driven by prospectivity analysis with the goal to design the best completion on the basis of the rock-quality data available. During completions monitoring, the designs are updated on the basis of the actual field pump rates and quantities of proppant pumped to estimate actual hydraulic- and propped-fracture characteristics. The effective fracture geometry is determined on the basis of well-production calibration. Wellbore and completion problems could be diagnosed in this analysis, including damage of fractures, fluid behavior, and well interference. We applied this framework to wells completed in the EFS. The reservoir-quality variability is based on petrophysical evaluation of logs acquired on all study wells. The characteristics of propped fractures were estimated on the basis of geomechanical modeling of actual field pumping measurements. Even though the fractures extended above and below the target interval of the EFS, they were successful in creating the desired half-length from a design point of view. It was also observed that not all the clusters matured, because of the stress-shadow effect. The produced fluids in these wells ranged from black oil to gas condensate. Well interference was observed as a production penalty factor in well-performance analysis. The behavior of current wells was used to design optimal completions for wells that were planned to be completed. This framework uses common data sets collected by a majority of operators. It provides intelligence for completion optimization of future wells after thorough investigation into fracture design, completion operation, and effective fracture characteristics. It is a systematic approach to optimized single-well design and field development (multiple wells, pad drilling).

Making optimal well spacing decisions in unconventional plays is critical for commercial viability. Given the huge areal extent of these plays and low permeability, a large number of wells are needed to optimally extract the resource. The well spacing decision has to incorporate changes in geology/reservoir characteristics, completion methodology, presence of offset wells, and economic constraints. This work shows the impact of changes in reservoir properties such as permeability, completion properties as fracture spacing and completion footprint or the areal configuration of the stimulated reservoir volume (SRV) in determining optimal well spacing. As additional development or infill wells are drilled in a section, the possibility of SRV overlap increases. When the stage/cluster placement is not staggered between the neighboring wells, the created fractures may intersect resulting in SRV destruction i.e. the fracture area accessible to the neighboring wells is less than the total fracture area created in absence of SRV overlap. With staggered placement of stages, the created fractures are at an offset and the SRV's overlap without the fractures intersecting. This results in accelerated depletion of the region between the wells by reducing the rock volume each hydraulic fracture has to drain. Thus, the neighboring wells rob some late life production potential by draining the reservoir within the study well drainage volume. The impact of the percentage of fracture overlap, fracture spacing, and reservoir permeability on overall recovery and economic value is evaluated using synthetic models. For the scenario of SRV destruction, the NPV decreased with increasing SRV overlap. With staggered placement of fractures, there is a minor loss in NPV for less than 50% SRV overlap under the economic constraints considered. Higher than 50% overlaps may be detrimental depending on permeability and fracture spacing. Changes in cost/economic constraints also impact optimal well spacing. The presented results will assist operators in planning closer well spacing by optimizing capital expenditures and hydrocarbon recovery.