Unal, Ebru (University of Houston) | Siddiqui, Fahd (University of Houston) | Rezaei, Ali (University of Houston) | Eltaleb, Ibrahim (University of Houston) | Kabir, Shah (University of Houston) | Soliman, Mohamed Y. (University of Houston) | Dindoruk, Birol (Shell International Exploration and Production, Inc.)
Inter-well connectivity (IWC) is one of the most significant properties when evaluating the success of a waterflood. This connectivity has been obtained from various physics-based methods such as simulations, tracers and using heuristics and semi-analytical tools like capacitance-resistance model (CRM). Production and injection data are a key piece of information required to compute the IWC. In this study, we present a new method for estimating IWC using signal processing techniques on the wavelet transform of the injection and production rate data.
First, the injection and production rates are subjected to multiresolution analysis using the wavelet transform to determine the detail coefficients. The variance of the detail coefficients is then computed and is ready to be processed using various signal processing techniques. Signal processing techniques such as cross-correlation, time lag, Spearman correlation, and Kendal correlation are used to identify the level of relationship between the processed injection and production data in wavelet scale space. Based on the correlation coefficients, a new IWC link parameter is proposed for characterizing the IWC between well pairs. The IWC link parameters between well pairs are then plotted for visual representation.
We created several simulation models for multi-well systems, established water-flood patterns, and for randomly placed wells to establish the new IWC link parameter. The resulting injection and production rates were analyzed using the methodology above and the new IWC link parameter is established in terms of cross-correlation coefficient. We also performed several simulations for a heterogenous reservoir to compute and compare the accuracy of the new IWC link parameter. Finally, the methodology is subjected to real field waterflooding, and compared against the CRM results, which shows a good agreement. The visual representation gives new insight into whether the connectivity is being affected by the reservoir or from near wellbore events (such as changes in skin).
This study integrates signal processing techniques and waterflood IWCs. Novel use of wavelet transforms coupled with variance for processing the injection and production rate data is proposed. It must be emphasized that wavelet is used in this context for processing and not for smoothing or data compression. Ultimately, this method can be implemented as a real-time automated monitoring system. Moreover, the new IWC link parameter provides insights by identifying problematic IWC, well-completion issues, and high perm channels for taking timely operational decisions.
In most US unconventional resources development, operators usually first drill the parent wells to hold their leases, and then infill wells are drilled. A challenge raised from this process is the well-to-well interference or frac-hits. Fractures in infill wells have a tendency to propagate toward the depleted region induced by the pressure sink of the parent well, resulting in asymmetric fracture growth in infill wells and frac-hit with the parent well. One of the available mitigation methods is to inject water into the parent well to re-pressurize the depleted region. Though several papers have released positive results from their numerical studies, both negative and positive responses are reported from filed applications. This paper focused on identifying the mechanism and key factors controlling the effectiveness of the subsequent parent well water injection. A coupling reservoir geomechanical model was built to evaluate the pressure and stress change caused by the parent well production and subsequent parent well water injection. The reservoir and geomechanical models are prepared based on a dataset from Eagle Ford Shale. At desired time steps, pressure distribution from reservoir simulation is used to calculate the corresponding stress status.
In this numerical simulation study, both reservoir properties and operating conditions are considered. Considering the production loss during the parent well injection, the maximum injection time is set to be 1 month. The magnitude and orientation of horizontal principal stresses within and around the depleted region are used as a criterion to evaluate the effectiveness of subsequent parent well injection. A general observation is that between two adjacent fracture clusters, 3 regions could be identified whose behaviors are significantly different during production and injection. The subsequent water injection could only restore the pressure and stress in region 1, which is within 10 ft to the fractures. Region 2 is severely depleted but the injection of 1 month generates no improvement in this region due to the low matrix permeability. Region 3 might exist, where oil is not produced, but Shmin reduces and this reduction could not be restored through injection of 1 month. If the injection generates a relatively uniform pressure distribution, then SHmax angle change could be reduced to 0. We also observed that: (1) for our case, an injection pressure equal to the initial reservoir pressure is recommended. Using low injection pressure, Shmin is found out to be lowest in fractures, which may make infill well fractures tend to propagate into and hit the parent well fractures. However, if injection pressure is increased to larger than the initial reservoir pressure and smaller than the minimum horizontal stress, the improvement is insignificant; (2) Comparison between uniform and non-uniform hydraulic fracture geometries shows that hydraulic fracture geometry mainly affects the depletion region far away from the wellbore. i.e. along the long fracture tips. After injection, in the case with long uniform fractures, the Shmin value in long fracture tips is still lowest. (3) An SRV with high permeability significantly extends the depletion region. If the permeability is not large enough i.e. 0.01 mD, after injection of 1 month, the restored Shmin is about 1000 psi lower than the base case without SRV. (4) Using low bottomhole pressure in production, restored pressure and stress are about 500 psi lower than the base case; and due to the large pressure contrast between region 1 and region 2, the SHmax angle change could not be reduced. (5) In a reservoir with normal pressure, as the pressure change is not large, it is easier for the subsequent injection to take effect.
This paper provides significant insights into how to design a successful subsequent water injection process in a parent well, mitigate the negative effects of frac-hits, and maximize production of both parent and infill wells.
Produced water re-injection (PWRI) has been used in the oil industry in concept and application. The long-term injectivity of PWRI wells often declines for various reasons, including but not limited to, complex fracture propagations from injection wells to production wells, potential cap rock interference, and formation damage by suspended solids, and inadequate pumping capacity to maintain desired and favorable fracture propagation conditions.
In fracture modeling, in-situ conditions of the target sand formations (e.g. stress magnitudes and direction, Poisson's Ratio, Young's Modulus, temperature, thermal expansion coefficient, and reservoir properties) has significant effects on fracture propagation and injectivity. The importance of these parameters are noteworthy, during the planning stage of the PWRI, these parameters should be characterized as accurately as possible for prediction of fracture dimensions to be propagated from injection wells to production wells. Other operational parameters, such as the number of injection wells, well trajectory, and injection water temperature and pump capacity can be optimized to determine and maintain the long-term injectivity and fracture propagation without interfering with other production wells and especially the cap rock.
In this paper, PWRI modeling software was used to model fracture propagation and injectivity during PWRI periods. Two cases were studied for planning and decision-making of PWRI application in sand formations. In the first case, the fracture propagation into upper cap rock was studied for various water injection volumes and solids concentrations. The fracture propagation was observed with increasing reservoir pressure for a continuous 15 years of injection and the stress profile contrast. In the second case, fracture propagation analysis of water injection wells was performed with potential completion problems (i.e. tubing to annulus communication or casing shoe bursting) and interference between injection and production wells. The results demonstrate that for both cases, the injection fluid temperature was an important factor that could considerably change the fracture length size and provided information about the fracture propagation from injection to production wells. The fracture size and injectivity index also depended on the concentration of total suspended solids that affected the injectivity.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
Chiotoroiu, Maria-Magdalena (OMV E&P) | Clemens, Torsten (OMV E&P) | Zechner, Markus (OMV E&P/Stanford University) | Hwang, Jongsoo (University of Texas) | Sharma, Mukul M. (University of Texas) | Thiele, Marco (Streamsim/Stanford University)
Waterflooding can lead to substantial incremental oil production. Implementation of water injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as inability to estimate a value precisely) a company is willing to take.
One of the key risks for water injection into a shallow reservoir is injection induced fractures extending into the caprock. If this risk is seen as "Intolerable" in an As Low As Reasonable Practicable (ALARP) analysis a decision may be made to not proceed with the project., In this study we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes and fracture propagation in the sand and bounding shale.
The risk of fracture growth into the caprock was assessed by conducting Monte-Carlo simulations considering a set of modelling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters where the risk of fracture height growth was acceptable. Our simulations also allowed us to identify important factors that impact caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk of the caprock integrity is reduced. This requires introducing a limit for the Bottom Hole Pressure (BHP) including a safety margin.
The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parametrisation of the model, sampling from the distribution of parameters and distance-based Generalized Sensitivity Analysis (dGSA) as well as probabilistic representation of the results.
The dGSA can be used to determine which parameter has a strong impact on the BHP and hence the project and should be measured if warranted by a Value of Information analysis.
The final development option to be chosen depends on a traditional NPV analysis.
Hwang, Jongsoo (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin) | Amaning, Kwarteng (Tullow Ghana Limited) | Singh, Arvinder (Tullow Ghana Limited) | Sathyamoorthy, Sekhar (Tullow Ghana Limited)
Understanding injectivity is a critical element to ensure that sufficient volumes of water are being injected into the reservoir to maintain reservoir pressure, to ensure good reservoir sweep and minimize well remediation. It is, however, challenging to describe the large injectivity changes that are sometimes observed in injectors operating under fracturing conditions. This study presents a field case study with the following objectives: 1) explain the complicated injectivity changes caused by fracture opening/closure with injection-rate variations, 2) define a safe operating envelope (for injection pressure and rate) that ensures fracture containment and injection into the target zone, and 3) prescribe how the injection rate should be changed to achieve higher injectivities. Injector operating conditions are developed using results from a full 3-dimensional fracture growth simulation to ensure fracture containment in a multi-layered reservoir.
We present field injectivity observations, a comprehensive simulation workflow and its results to explain injector performance in a deep-water turbidite sand reservoir with multiple splay sands. Understanding the impact on fracture propagation and containment allows us to make quantitative suggestions for the operating envelopes for long-term injection-production management. Strategies for high-rate injection to sustain the injection well performance long-term are discussed.
Simulation results show that, at injection rates over 5,000 bwpd, injection induced fractures propagate. Fracture closure induced by injection shut-down is used to compute the bottom-hole pressure decline as a function of time. The fracture opening/closure events and the thermally induced stress were the primary factors impacting injectivity. The simulation results suggested several ways to improve the injectivity while ensuring fracture containment. Injection under fracturing conditions into a single zone at a high rate is shown to be feasible and this allows us to support a substantial increase in injectivity. This must, however, be done at pressures that will not cause a breach in the bounding shales. The 3-dimensional fracture simulations identified the operating pressure and rate envelope to maximize the injection rates while minimizing the risk of breaching the cap rock and inter-zone shales.
Nagar, Ankesh (Cairn Oil & Gas – Vedanta Limited) | Dangwal, Gaurav (Cairn Oil & Gas – Vedanta Limited) | Maniar, Chintan (Cairn Oil & Gas – Vedanta Limited) | Bhad, Nitin (Cairn Oil & Gas – Vedanta Limited) | Goyal, Ishank (Cairn Oil & Gas – Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas – Vedanta Limited) | Parashar, Arunabh (Cairn Oil & Gas – Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas – Vedanta Limited)
The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains.
The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. .
Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
Aidagulov, Gallyam (Schlumberger Dhahran Carbonate Research Center) | Gwaba, Devon (Schlumberger Dhahran Carbonate Research Center) | Kayumov, Rifat (Schlumberger Middle East S.A.) | Sultan, Abdullah (King Fahd University of Petroleum and Minerals) | Aly, Moustafa (King Fahd University of Petroleum and Minerals) | Qiu, Xiangdong (Schlumberger Dhahran Carbonate Research Center, Now with Branch of Sinopec International Petroleum Service Corporation) | Almajed, Haidar (King Fahd University of Petroleum and Minerals) | Abbad, Mustapha (Schlumberger Dhahran Carbonate Research Center)
Carbonate reservoirs host a significant amount of hydrocarbon reserves in the Middle East and worldwide. In matrix acidizing stimulation, hydrochloric acid (HCl) is commonly injected into the well at pressures less than fracturing pressure to dissolve the carbonate rock and create high-conductivity channels, known as wormholes. Wormholes propagate through the damaged near-wellbore zone connecting the well with the reservoir. In this work, we aim to study the effects of pre-existing fractures on wormhole development.
Matrix acidizing processes were reproduced in controlled laboratory experiments where a 15% HCl solution was injected into a borehole drilled in a carbonate block sample containing pre-existing fractures, allowing the acid to penetrate radially into the rock sample. The experiment was conducted inside a polyaxial load frame to accommodate large block samples (20×16×16 in.). Prior to acid injection, the block was fully saturated with water and taken to 2,000-psi pore pressure and 4,000-psi confining stress to simulate downhole conditions. To evaluate the created wormholes, the tested block was cut open along the fractures followed by X-ray CT scanning of selected zones.
Here we report experimental results for matrix stimulation of one Indiana limestone block containing a series of parallel pre-existing fractures. Acid was injected at a constant rate through the 1-in. diameter borehole containing an 8-in.-long openhole section in the center of the block. Although the acid injection pressure was maintained below the pressure required to open the fractures, acid breakthrough was found to be governed by the pre-existing fractures. Indeed, unlike similar radial acidizing experiments in intact blocks, there were no indications of wormholes exiting the outer faces of the block. Moreover, the post-test evaluation of the central fracture along the openhole section clearly revealed the wormholes that etched the fracture faces. However, a closer look into the stimulated openhole section showed that the wormholes initiated in other directions inside the matrix as well. An X-ray CT scan of a 4-in. diameter cored borehole regions allowed us to compare the density and characteristics of the wormhole growth along the fracture and into the matrix.
Although radial acidizing experiments describe more closely real conditions of matrix acidizing, few cases have been published, particularly for large-block experiments. The large-scale block experiments presented in this study provide new insights on the impact of pre-existing fractures on wormholing mechanisms.
Xu, Ting (Sinopec Petroleum Exploration & Production Research Institute) | Pu, Jun (Sinopec Petroleum Exploration & Production Research Institute) | Qin, Xuejie (Sinopec Petroleum Exploration & Production Research Institute) | Wei, Yi (Sinopec Petroleum Exploration & Production Research Institute) | Song, Wenfang (Sinopec Petroleum Exploration & Production Research Institute)
South Ordos sandstone reservoir is mainly featured by tiny pore, which mainstream throat radius is around 50nm, high filtration resistance, resulting in low oil productivity and more obvious non-linear seepage characteristics. As of low formation pressure, well production is poor and declines dramatically, therefore primary recovery is hard to sustain effective development for the reservoir. The core problem of tight oil development focuses on the evaluation of tight matrix flowing capability and reservoir producing condition.
In the paper, in Ordos typical tight oil basin, by means of microscopic flowing simulation, numerical simulation as well as lab experiments results, single-phase and oil-water two-phrase flowing mechanisms have been analyzed, revealing tight oil single phase percolating resistance and movable oil saturation, providing key evaluation parameters for effective reservoir division. For oil-water two-phase flowing, Jamin effect is so serious that water flooding is hard to displace the oil in micro-pores, accordingly relative permeability and displacement efficiency are calculated. Tight matrix-fracture coupling model recovery mechanism have been analyzed, effective producing radius and mechanism of matrix are defined in the condition of fracturing horizontal wells developing, according to which productivity percentage of Ordos tight oil between fracture and matrix have been determined. On basis of geology evaluation and reservoir engineering analysis, correlation of geological properties-well dynamic characteristics are set up, then influencing factors have been studied to identify tight oil producing conditions on depletion development at different oil price. As different classified fracture developed in the reservoir, water flooding producing condition has been studied, laying the foundation for study of effective development method and technical strategy.
Our research indicates that Ordos tight matrix is of low productivity, with movable water saturation increasing, well productivity sharp decline. During production period, production ratio from fracture is only amounted to 6~14% of accumulation oil. Fully excavating the potential of matrix reserves is predominant to achieve effective development of tight oil. Owing to high start-up pressure gradient, as high as 0.1~0.2MPa/m, for water flooding development, well spacing should be reduced to 50m□ to set up pressure response without fracture developing. While in Ordos basin natural fracture is developed, water channeling is so heavy that accumulative oil is lower than depletion method. CO2 start-up pressure gradient is far smaller than that of water flooding with composite EOR mechanisms, expected to be an effective injection medium for tight oil.
It is a critical period how so many shut-in wells could be revitalized under low oil price condition. Relying on research results, Ordos tight oil new development method target has been determined, promoting application research and pilot test on CO2-gelled fracturing fluid and effective injection fluid sustaining matrix displacing pressure in tight oil development.