Impact of Delayed Flowback on Well Performance: Case Study

Due to a resource optimization and efficiency improvements, wells that are hydraulically fractured in the tight gas Barik Formation of the Khazzan Field in the Sultanate of Oman are often temporarily left shut-in directly following a large scale massive hydraulic fracturing stimulation treatment. Extensive industry literature has often suggested (and reported), that this may result in a significant direct loss of productivity due to the delayed flowback and the resulting fracture conductivity and formation damage. This paper will review the available data from the Khazzan Field address these concerns; indicating where the concerns should and should not necessarily apply. The Barik Formation in the Khazzan Field is an over-pressured gas-condensate reservoir at 4,500 m with gas permeability ranging from 0.1 to 20 mD. The average well after hydraulic fracturing produces 25 MMscfd and 500 bcpd against a wellhead pressure of 4,000 psi. A typical hydraulic fracturing stimulation treatment consists of 14,000 bbl of a borate-crosslinked guar fluid, placing upwards of 1MM Lbs of high conductivity bauxite proppant within a single fracture. In order to assess the potential production loss due to delayed flowback operations, BP Oman performed a suite of formation damage tests including core samples from the Barik reservoir, fracture conductivity considerations and dynamic behaviors. Additionally, normalized production was compared between offset wells that were cleaned-up and put onto production at different times after the hydraulic fracturing operations. Core tests showed a range of fracture conductivities over time with delayed flowback after using the breaker concentrations from actual treatments. As expected, enhanced conductivity was achieved with additional breaker. The magnitude of the conductivity being created in these massive treatments was also demonstrated to be dominant with respect to damage effects. Finally, a normalized comparison of an extensive suite of wells clearly showed no discernible loss of production resulted from any delay in the flowback operations. This paper describes in details the workflow and resulting analysis of the impact of extensive shut-in versus immediate flowback post massive hydraulic fracturing. It indicates that the impact of such events will be limited if the appropriate steps have been taken to minimize the opportunity for damage to occur. Whereas the existing fracturing literature takes the safe stance of indicating that damage will always result from such shut-ins, this paper will demonstrate the limitations of such assumptions and the flexibility that can be demonstrated with real data.

Impediments to Refracturing Success in Shale Reservoirs

Stimulations in early horizontal wells in most shale plays are characterized by few and widely spaced perforation clusters, and low amounts of injected fracturing fluid and proppant. Low recovery from these wells has motivated refracturing although outcomes have been interpreted to range from successful to minimal impact based on operator specific evaluations. To tailor available technologies and improve quantification of upsides, there is need for mapping the spatial distribution of remaining resources and developing simpler but reliable analytical techniques. In this study, hydraulic fractures were assumed to be planar in a matrix with low porosity and ultra-low permeability. Consideration of natural fractures and their interaction with stimulation fluids led to addition of distributed fracture networks adjacent to the planar hydraulic fractures to define the composite fracture corridors. A sector model with the aforementioned architecture was used in reservoir simulation to investigate induced temporal and spatial drainage. These findings were used to explain the efficacy of widely used refracturing techniques and how post-refracturing reservoir response can be analyzed. Results from reservoir simulation showed remaining reserves were in the matrix between earlier placed hydraulic fractures aligned along initial perforation clusters, and beyond tips of hydraulic fractures. Upside from refracs could come from creation of new fractures in the matrix between earlier placed fractures and extension of tips of early fractures into virgin matrix. Assessment of these scenarios found the former to be optimal although depletion and existing perforations would limit the stimulation efficiency of new perforations. The second scenario would require large volumes of fracturing fluid to re-initiate fracture propagation. Yet this could trigger interference with offsets or affect drilling and stimulation of planned wells in adjacent acreage. For treatment efficiency, re-casing horizontal wells with competent liners and use of coiled tubing with straddle packers appears a better solution for bypassing old perforations. For the near wellbore and far field, re-stimulating new perforations at low injection rates could allow extension of fractures in virgin matrix surrounded by depleted strata. Real-time surveillance would be essential for mapping flow paths of refracturing fluid. For assessment of refracturing, actual and simulated flow exhibited persistent linear flow (PLF) that could be matched by Arps hyperbolic equation with a b value of 2. Incorporation of a novel fracture geometry factor (FGF) yielded an Arps-based equation that was tested on North American shale refracturing cases that often use post-treatment peak rate and wellhead pressure as measures of success. This study identified factors hindering the success of refracturing and proposed a modified Arps hyperbolic equation to analyze refracturing production data.

Multiphase Flow Boosting Without Using a Mechanical Multiphase Pump – Use of Innovative Surface Mounted Technology for Boosting Production from Inactive Multiphase Wells

Depleting reservoir pressures of mature fields or wells backing out due to high production line pressures can cause severe restriction in production from many oil wells, eventually leading to a complete cessation of production. These wells, however, still have considerable hydrocarbon reserves that can be recovered. Conventional methods to bring such marginal or inactive wells back into production involve power hungry multi-phase pumps or well intervention techniques such as N2 injection, workover, redrilling and artificial lift systems. Such methods are highly expensive and may require substantial infrastructure, especially on offshore satellite platforms which have limited facilities and space. Multi-Phase Surface Jet Pumps (MPSJPs), innovatively combined with novel compact separation, provide a surface mounted, compact, maintenance free and simpler method for boosting production from inactive multi-phase wells, without consuming any electrical power or fuel gas and avoiding any well intervention. Multi-Phase Surface Jet Pumps (MPSJPs) are passive devices which use the energy of existing high pressure single/multi-phase fluids to reduce the Flowing Wellhead Pressure (FWHP) of low pressure multi-phase wells and boost their pressure to the downstream production header pressure. This patented system involves the use of a compact in-line separator upstream of the MPSJP to separate the gas & liquid phases and use the predominant liquid phase as the high-pressure motive fluid. MPSJPs can be used on their own or in combination with other boosting systems (e.g. ESPs, gas lift etc.). The applications also include revival of watered out, idle oil and gas wells. Results from multiple worldwide applications have shown that MPSJPs can successfully boost production from low producers as well as revive dead wells that have not been flowing for a period of time. Wellhead pressures have been considerably reduced and production increases have ranged from 20% to 40% per well. The advantages that MPSJPs offer over conventional technologies such as Multi-phase pumps, ESPs and well intervention techniques are several. MPSJPs are surface mounted (so well intervention is not required), comparatively low cost, have no moving parts, consume zero fuel gas/electrical power, have low footprint and use already available fluid energy. They are tolerant to variations in flow conditions, gas volume fractions (GVF) and associated slugging. They reduce the CO2 footprint by not consuming power and provide a radical, innovative, economical and environmentally friendly alternative to conventional methods. This paper discusses the use of MPSJPs and cites various case studies. The design and operational criteria are also highlighted.

Enhanced Production with Self-Driven Multi-Phase Pumps

Some wells are either producing intermittently or ceasing against the trunk line pressure due to low flowing wellhead pressure. OLS with MPP provides the flexibility such as boosting pressure from low flowing wellhead pressure well to the existing trunk lines. The MPP has a wider pressure operating envelope to accommodate the less flowing wellhead pressure well in long run. Incremental Oil & gas production will be realized by lowering the FWHP on this well using the OLS. Multi-Phase Pumps solutions have sustained production from marginal and restarted non-producing wells. Production gains are highly dependent on the reservoir and well parameters.

First Successful Application of Casing in Casing CiC Refracturing Treatment in Shale Gas Well in China: Case Study

With active hydraulic fracturing performed since 2012, the Fuling shale gas field in China is one of the largest shale gas fields outside of North America. Recently, a Casing-in-Casing (CiC) refracturing treatment was successfully implemented, resulting in production beyond expectations. This was the first successful application of a CiC refracturing treatment in a horizontal shale gas well in this region, thus providing a new option for refracturing horizontal wells in China. Bullheading diversion refracturing with diverting balls was previously attempted in this field with high initial production observed; however, production was inconsistent and quickly declined. Therefore, the operator decided to attempt a CiC refracturing method in an understimulated candidate well. This involved installing and cementing 3.5-in. casing in 5.5-in. casing to effectively isolate the perforations, which enabled plugging and perforating operations in the reconstructed wellbore for an effective refracturing treatment. A customized refracturing design integrated the production profile, residual recoverable reserves, and the specific 5.5- × 3.5-in. reconstructed wellbore limitation. The length of the 3.5-in. casing was optimized to be as short as possible but still cover the original perforations, and high-performance slickwater was used to reduce pipe friction, thus increasing the treatment rate. An engineered breakdown approach was employed for improved fracture initiation. Additionally, more clusters were added between the original clusters and, based on production profile results, some of the original understimulated clusters with little proppant placement were reperforated. To overcome the impact of depleted fractures, a self-degradable particulate diverting agent was used to propagate new fractures, allowing access to new rock to increase total reserve recovery. The treatment in the reconstructed wellbore was successful, with 21 stages fractured in 12 days, achieving 100% placement of the designed proppant and fluid. A treatment rate of 7 to 12 m3/min from the toe to heel was executed as designed. Test production of 183,800 m3/D was also achieved with a recovery rate of 88.1%. Production has remained consistent and wellhead pressure has remained steady at a high level throughout the first two months of production. CiC refracturing technology helps overcome common disadvantages experienced with traditional refracturing techniques, such as poorly placed proppant and fluid and inconsistent production. CiC refracturing not only allows exploitation of bypassed reserves from original fractures, but also allows precise stimulation of new rock to obtain the highest reserve recovery. The successful implementation of this case study illustrates the reliability of CiC refracturing technology and provides valuable experience to be used during future regional horizontal well refracturing.

Integrated Production Model as a Tool for Optimization the Development Strategy of the Sakhalin Oil and Gas Condensate Field

A fully integrated production model (IPM) has been implemented in the Sakhalin field to optimize hydrocarbons production and carried out effective field development. To achieve our goal in optimizing production, a strategy has been accurately executed to align the surface facilities upgrade with the production forecast. The main challenges to achieving the goal, that we have faced were:All facilities were designed for early production stage in late 1980's, and as the asset outdated the pipeline sizes, routing and compression strategies needs review.Detecting, predicting and reducing liquid loading is required so that the operator can proactively control the hydrocarbon production process.No integrated asset model exists to date. The most significant engineering tasks were solved by creating models of reservoirs, wells and surface network facility, and after history matching and connecting all the elements of the model into a single environment, it has been used for the different production forecast scenarios, taking into account the impact of infrastructure bottlenecks on production of each well. This paper describes in detail methodology applied to calculate optimal well control, wellhead pressure, pressure at the inlet of the booster compressor, as well as for improving surface flowlines capacity. Using the model, we determined the compressor capacity required for the next more than ten years and assessed the impact of pipeline upgrades on oil gas and condensate production. Using optimization algorithms, a realistic scenario was set and used as a basis for maximizing hydrocarbon production. Integrated production model (IPM) and production optimization provided to us several development scenarios to achieve target production at the lowest cost by eliminating infrastructure constraints.

Nano Chemical Design for Excessive Water Production Control in Taq Taq Oil Field

A common problem in oil and gas field is premature and excessive water production through higher permeable thief zone, faults, water conning or channeling and natural or induced fracture. Excessive water production impacts the economics of a well through increasing rate of corrosion, emulsion and scale formation, consequently shortening its production life and lowering flowing wellhead pressure. There are several techniques used to control excessive water production such as chemical and mechanical. In this work a novel chemical approach was followed to tackle excessive water production in Taq Taq oil field located in Kurdistan Region Iraq. Water production into the reservoir was determined to be through the fractures as the reservoir units are highly fractured carbonates. Therefore, the chemicals designed by this work were to reduce excessive water production selectively and fracture connectivity in the zones where excessive water production is expected. Three nano-solutions have been prepared and investigated for their rheological properties. Only one is selected and met the field screening criteria. The composition of the nano-solutions were mainly polyacrylamide mixed with nano composite of cement, clay and inorganic cross-linker. All nano-solution underwent extensive screening and studied for their mechanical strength, toughness and tensile module. Results showed that nano-solutions strength increases with increasing the nano concentration. Similarly, their viscosity and degradation resistance are improved noticeably with nano composites. The scanning Electron Microscopy (SEM) was also used to characterized the nano size and distribution studied by this work.

Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

Affected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

Force Analysis of Logging Cable in Deep Well

With the increase of deep wells, high temperature and high pressure wells and complex wells, the demand for logging is also increasing. Wireline logging is an important technical means to obtain downhole data in the process of petroleum testing. This paper establishes a cable mechanics model by analyzing the main influencing factors of the cable force in the inclined well section or the vertical well section. Calculate the lifting power of the tool. Through logging calculation, the force change law of the downhole cable and tool string is obtained when the wellhead pressure changes.

An Integrated Modeling Approach to Estimate the Shut-in Wellhead Pressure for Well Integrity Applications – Case Study

Oil and gas operators must measure or calculate the shut-in wellhead pressure for well integrity applications. Some operators adopt a method that gives satisfactory results for dry gas and lean gas condensate. They are using the steady-state simulator to calculate the wellhead pressure at a very low gas rate. The friction losses become negligible, and the only losses are due to hydrostatic head simulating (to some extent) the shut-in condition. This method again can work well with oil producers with low GOR/Bubble point pressure as the production string will be nearly a single phase. The problem is that this method is inaccurate for high GOR/CGR wells because of phase redistribution and the error can be significantly high. Phase redistribution occurs After shut-in, liquid droplets will accumulate at the bottom of the well. The interface liquid/gas will move up with sometimes liquid cushion is being re-injected back in the reservoir due to gravity or gas expansion in the tubing while the gas/liquid interface will move down a little. Many factors affect the behavior, including the well deviation, fluid properties, and the productivity and the injectivity of the formation. Thus, simulating this behavior requires a dynamic multiphase simulation. As some of the fluids might return to the formation, as a result of compressibility, coupling with a numerical reservoir simulation to model the near wellbore is also necessary. In this paper, we applied a dynamic multiphase model to predict the shut-in wellhead pressure. We used an uncertainty analysis approach to investigate the effect of many parameters on the accuracy of the results. We presented all recommended calculation procedures with a guide to minimizing the uncertainty associated. We presented our approach to three actual wells with different configurations and fluid properties with a deviation of +-10% of the real measurements.