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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
Abstract Maximum horizontal stress (SH) and stress path (change of SH and minimum horizontal stress with depletion) are the two most difficult parameters to define for an oilfield geomechanical model. Understanding these in-situ stresses is critical to the success of operations and development, especially when production is underway, and the reservoir depletion begins. This paper introduces a method to define them through the analysis of actual minifrac data. Field examples of applications on minifrac failure analysis and operational pressure prediction are also presented. It is commonly accepted that one of the best methods to determine the minimum horizontal stress (Sh) is the use of pressure fall-off analysis of a minifrac test. Unlike Sh, the magnitude of SH cannot be measured directly. Instead it is back calculated by using fracture initiation pressure (FIP) and Sh derived from minifrac data. After non-depleted Sh and SH are defined, their apparent Poisson's Ratios (APR) are calculated using the Eaton equation. These APRs define Sh and SH in virgin sand to encapsulate all other factors that influence in-situ stresses such as tectonic, thermal, osmotic and poro-elastic effects. These values can then be used to estimate stress path through interpretation of additional minifrac data derived from a depleted sand. A geomechanical model is developed based on APRs and stress paths to predict minifrac operation pressures. Three cases are included to show that the margin of error for FIP and fracture closure pressure (FCP) is less than 2%, fracture breakdown pressure (FBP) less than 4%. Two field cases in deep-water wells in the Gulf of Mexico show that the reduction of SH with depletion is lower than that for Sh.
Abstract The subject of this paper is the application of a unique machine learning approach to the evaluation of Wolfcamp B completions. A database consisting of Reservoir, Completion, Frac and Production information from 301 Multi-Fractured Horizontal Wolfcamp B Completions was assembled. These completions were from a 10-County area located in the Texas portion of the Permian Basin. Within this database there is a wide variation in completion design from many operators; lateral lengths ranging from a low of about 4,000 ft to a high of almost 15,000 ft, proppant intensities from 500 to 4,000 lb/ft and frac stage spacing from 59 to 769 ft. Two independent self-organizing data mappings (SOM) were performed; the first on completion and frac stage parameters, the second on reservoir and geology. Characteristics for wells assigned to each SOM bin were determined. These two mappings were then combined into a reservoir type vs completion type matrix. This type of approach is intended to remove systemactic errors in measuement, bias and inconsistencies in the database so that more realistic assessments about well performance can be made. Production for completion and reservoir type combinations were determined. As a final step, a feed forward neural network (ANN) model was developed from the mapped data. This model was used to estimate Wolfcamp B production and economics for completion and frac designs. In the performance of this project, it became apparent that the incorporation of reservoir data was essential to understanding the impact of completion and frac design on multi-fractured horizontal Wolfcamp B well production and economic performance. As we would expect, wells with the most permeability, higher pore pressure, effective porosity and lower water saturation have the greatest potential for hydrocarbon production. The most effective completion types have an optimum combination of proppant intensity, fluid intensity, treatment rate, frac stage spacing and perforation clustering. This paper will be of interest to anyone optimizing hydraulically fractured Wolfcamp B completion design or evaluating Permian Basin prospects. Also, of interest is the impact of reservoir and completion characteristics such as permeability, porosity, water saturation, pressure, offset well production, proppant intensity, fluid intensity, frac stage spacing and lateral length on well production and economics. The methodology used to evaluate the impact of reservoir and completion parameters for this Wolfcamp project is unique and novel. In addition, compared to other methodologies, it is low cost and fast. And though the focus of this paper is on the Wolfcamp B Formation in the Midland Basin, this approach and workflow can be applied to any formation in any Basin, provided sufficient data is available.
Aljaberi, Jaber (King Fahd University of Petroleum & Minerals) | Alafnan, Saad (King Fahd University of Petroleum & Minerals (Corresponding author)) | Glatz, Guenther (King Fahd University of Petroleum & Minerals) | Sultan, Abdullah S. (King Fahd University of Petroleum & Minerals) | Afagwu, Clement (King Fahd University of Petroleum & Minerals)
Summary Shale-matrix-associated transport phenomena exhibit multiple mechanisms including advective-, diffusive-, and adsorptive-driven transport modes, depending on the pore type. Diffusive processes are governed by the shale organic constituents known as kerogens. Kerogens, composed of fine-scale organic microstructures, vary with respect to their petrophysical properties, depending on their origin and maturity level. The extent to which kerogens contribute to the overall transport is governed by their ability to diffuse hydrocarbons contained within. The diffusion coefficient is a crucial parameter used to quantify diffusivity based on the interactions between the host material and the diffusing molecules. Kerogen as a hosting medium allows for diffusion of natural gas at various rates based on several factors. One of these factors, kerogen porosity, is conjectured to significantly influence diffusive transport phenomena. In this paper, taking advantage of the predictive power of molecular dynamics (MD) simulation, we investigate the impact of kerogen porosity on the diffusivity coefficient of natural gas. Starting from a single type II kerogen macromolecule, several kerogen structures for a realistic range of porosity values were created and, subsequently, used for diffusivity calculations of methane molecules. Simulation results suggest a direct link between diffusion and kerogen porosity, allowing for delineation of the diffusion tortuosity factor. Furthermore, the microscale tortuosity–diffusivity relationship in kerogens was investigated at the reservoir scale by means of a shale permeability model. The results substantiate the critical impact of the diffusion process on the shale permeability.
Abstract Objective/Scope The objective of this paper is to highlight the fact that while in conventional drilling there can sometimes be no mud weight solution for drilling a particular narrow margin section without either exceeding the Leak Off Test value at the shoe, or falling below the Pore Pressure at section TD. In Managed Pressure Drilling (MPD) there is often a range of mud weight solutions that can be used to drill the section, but usually one optimum mud weight that should be used, based on different risk criteria that can be evaluated. The consequences of this are that when using MPD, it could be that the section risks have not been minimised and therefore more risk than necessary has been imported into the methodology. Whereas if all MPD mud weight solutions have been evaluated, together with their associated Surface Back Pressures, and the optimum selection made, then the mitigations can be specially tailored so that the remedial actions to any system failure are clearly planned in advance, reducing the overall risk level of the operation. Methods, Procedures, Process The methodology described in this paper demonstrates the process for choosing the optimal mud weight for drilling any well section using MPD, with worked examples. This process is especially applicable for drilling very narrow margin sections, for example with only 0.2 ppg window between Pore Pressure and Fracture Gradient. By enumerating the safety margins both at the previous casing shoe and at the proposed section TD, or any other point of interest, it is possible to rank the risks of kicks and losses in that section across a range of proposed mud weights and use this information to choose the optimal mud weight. Results, Observations, Conclusions The process of evaluating the options and outcomes of using different mud weights in MPD can not only lead to the best drilling solution for the section, but can also be used as a discussion tool between the drilling team and the subsurface team, to help elucidate the most likely risks to the operation and thereby mitigate those risks in the most appropriate way. Novel/Additive Information A further benefit of this approach is that the narrowest possible drilling windows can also be evaluated and as a result, options for extending TD and potentially eliminating casing strings can be considered, leading to considerable savings, which are highly prized at all times, but especially so in a low oil price environment.
Khalid, Ali (Weatherford International) | Ashraf, Qasim (Weatherford International) | Luqman, Khurram (Weatherford International) | Hadj-Moussa, Ayoub (Weatherford International) | Ghulam Nabi, Agha (Pakistan Petroleum Limited) | Bari Khan, Faizan (Pakistan Petroleum Limited) | Azhar Khan, Muhammad (Pakistan Petroleum Limited)
Abstract As oil and gas reserves mature the world over, operators are looking towards advanced methods of increasing the ultimate recovery from their ageing fields. An energy deficient country of Pakistan relies heavily on oil and gas imports. The country was once self sustaining in at least natural gas needs. A major portion of this gas was produced from the Field-X which was discovered in the 1950’s. The primary reservoir in Field-X is the YZ-Limestone reservoir which bears sour gas. Due to extensive production from the YZ-Limestone formation, the reservoir pressure has depleted to a mere 2.0 PPG in equivalent mud weight, and it being a naturally fractured limestone formation presents numerous drilling challenges. The operator has evaluated a potential higher pressured formation in the deeper horizons of sui field but that requires drilling through approximately 650-690 meters of the YZ-Limestone formation. This feat when attempted conventionally is plagued with numerous problems like, total lost circulation, differential sticking, influxes due to the loss of a sufficient hydrostatic head, and stuck pipe following well control events. To mitigate these challenges the operator, need an effective method to drill through this depleted formation without pumping heavy LCM pills, and multiple cement plugs across the massive cavernous thief zones in the YZ-Limestone formation which could have been detrimental to the production of nearby wells. Moreover, such remedies with specialized LCM’s and acid soluble plugs would have resulted in excessive material cost and non-productive time, which in some instances extended to a period of more than a month. To address the aforementioned challenges in drilling the YZ-Limestone formation, a multiphase managed pressure drilling system was suggested to drill the formation with minimal non-productive time and cost. Multiphase hydraulics were performed to assess appropriate pumping parameters for a near-balanced condition across the YZ-Limestone formation. A closed loop MPD equipment system was designed to help maintain near-balanced conditions in pumping and static (non-circulating) periods. The designed equipment system would also ensure that the risk of H2S exposure to the atmosphere was eliminated. The application of a closed loop nitrified mpd system on a recently drilled well proved to be highly successful and reduced the drilling time to just 28 hours by not only eliminating fluid lost circulation but by also delivering an extremely high rate of penetration of 39.2 m/hr. The successful and exemplary application of nitrified MPD has opened up a new horizon for the development of deeper prospects in the Field-X and similar neighboring fields. The paper outlines the design and execution of the closed loop nitrified MPD system.
Abstract An integrated 3D dynamic reservoir geomechanics model can provide a diverse 3D view of depletion-injection-induced field stress changes and the resulting deformation of both reservoir and overburden formations at various field locations. It enables the assessment of reservoir compaction, platform site subsidence, fault reactivation and caprock integrity associated with multiple production and injection reservoirs of the field. We demonstrated this integrated approach for a study field located in the South China Sea, Malaysia, which is planned for water injection for pressure support and EOR scheme thereafter. Reservoir fluid containment during water injection is an important concern because of the intensive geologic faulting and fracturing in the collapsed anticlinal structure, with some faults extending from the reservoirs to shallow depths at or close to the seafloor. Over 30 simulations were done, and most input parameters were systematically varied to gain insight in their effect on result that was of most interest to us: The tendency of fault slip as a function of our operation-induced variations in pore pressure in the reservoir rocks bounding the fault, both during depletion and injection. The results showed that depletion actually reduces the risk of fault slip and of the overburden, while injection-induced increase in pore fluid pressure will lead to a significant increase in the risk of fault slip. Overall, while depletion appears to stabilize the fault and injection appears to destabilize the fault, no fault slip is predicted to occur, not even after a 900psi increase in pore pressure above the pore pressure levels at maximum depletion. We present the model results to demonstrate why depletion and injection have such different effects on fault slip tendency. The interpretation of these geomechanical model results have potential applications beyond the study field, especially for fields with a similar geology and development plan. This is a novel application of 3D dynamic reservoir geomechanics model that cannot be obtained from 1D analytical models alone.
Widyanita, Ana (PETRONAS Research Sdn. Bhd.) | Cai, Zhong (PETRONAS Research Sdn. Bhd.) | Mat, M Noor (PETRONAS Research Sdn. Bhd.) | Ali, Siti Syareena (PETRONAS Research Sdn. Bhd.) | Hamid, Mohd Khaidhir (PETRONAS Research Sdn. Bhd.) | Jones, Ernest A (PETRONAS Research Sdn. Bhd.)
Abstract This paper focuses on the gas characteristics in caprock interval and the gas migration mechanisms from the carbonate reservoir into the caprock and its effects on caprock seal capacity. The workflow mainly includes three methods:(1) Gas geochemistry analysis from the GWD (Gas While Drilling) data to understand the gas composition, their distribution and mechanism for gas migration; (2) Petrophysical analysis to understand the rock types, petrophysical properties and the pore-throat system; and (3) Pore pressure prediction to understand the pressure sealing capacity of the caprock. Integrating the results from these three aspects, the sealing capacity can be evaluated by capillary pressure sealing, pore pressure sealing and the effects on the sealing efficiency for CO2. There are two gas migration mechanisms in the area: gas diffusion and gas advection. The gas in the caprock of Field A shows decreasing molecular weight trend from deep to shallow depths implying migration from the underlying carbonate reservoir by gas diffusion. However, the gas in the caprock of Field B where there is a gas chimney visible in the seismic data, has composition similar to the gas in carbonate reservoir, suggesting that the gas came from carbonate reservoir below by gas advection through faults and induced fractures and occurred simultaneously with the gas accumulation in the reservoir. There is also gas in the caprock above the gas chimney with lighter molecular weight representing gas that migrated from the gas chimney by gas diffusion. The caprock seal capability in the two fields are different. The gas in the carbonate reservoir in Field A can be sealed and trapped by the high displacement/entry pressure of the capillary pore-throat system and the abnormally high pore pressure in the caprock. The gas chimney at Field B would be connected to the carbonate reservoir below over geological time and there is effective seal enough to contain hundreds ft of gas column in the carbonate reservoir. The understanding of the leaking mechanism in these two fields is helpful for understanding the leakage scale, the effects on the sealing capacity, the risk evaluation and mitigation amendment.
Khalid, Ali (Weatherford International) | Ashraf, Qasim (Weatherford International) | Luqman, Khurram (Weatherford International) | Hadj Moussa, Ayoub (Weatherford International) | Ghulam Nabi, Agha (Pakistan Petroleum Limited) | Ahmed Baig, Umair (Pakistan Petroleum Limited)
Abstract With the energy sector in crisis the worldover, oil and gas operators continue to seek more effective and efficient methods to reach potential prospects. With sharply declining oil prices, it is imperative that operators minimize the non-productive time in the drilling of all wells. Many operators are actively seeking riskier exploration to establish a strong foothold in this volatile market. One such area of interest to operators is HPHT and beyond wells. An HPHT prospect carries a high-risk high-reward potential, therefore newer and advanced methods are being deployed to successfully drill and complete HPHT wells. The Makran Coastal belt in south western Pakistan is one such area containing a potential Ultra-HPHT prospect. Many operators had attempted to drill about 9 wells in the locality but never managed to reach target depth due to drilling operations being plagued with a large number of problems. The drilling problems included high pressure influxes, stuck pipe while controlling influxes, circulation losses with high mud weights and ECD’s, differential sticking against permeable formations, inefficient bottom hole pressure control due to mud weight reduction with high temperatures and swabbing from the formation due to having an insufficient trip margin. The operator was facing an extremely narrow drilling window in the target section. The maximum formation pressure was estimated to be around 2.29 SG while the maximum fracture pressure of the formation was estimated to be around 2.35 SG in EMW. It was abundantly clear that drilling with a conventional mud system would be impossible and impractical on all forthcoming wells. As it was of paramount importance to precisely manage the wellbore pressure profile, the operator decided to apply managed pressure drilling on a candidate well. By applying managed pressure drilling techniques the operator expected to drill the section with an underbalanced mud weight and maneuver the bottom hole pressure just above the pore pressure line and thereby avoid circulation losses, detect influxes early on and control influxes without the need of ever shutting in the well, account for mud density variations with temperatures by executing an advanced thermal hydraulics model in real time, mitigate swabbing from the formation again by maintaining a constant bottom hole pressure while tripping, and finally ascertain the downhole pressure environment by conducting dynamic formation pressure tests. The successful application of MPD enabled the operator to reach target depth for the first time in the history of the area. The paper studies the planning, design, and execution of MPD on the subject well.
This topic describes the effect of temperature on rock acoustic velocity. For consolidated rocks (Classes I, II, and V as defined in Rock acoustic velocities and porosity), the elastic mineral frame properties are usually only weakly dependent on temperature. This is true for most reservoir operations with the exception of some thermal recovery procedures. In the case of poorly consolidated sands containing heavy oils, velocities show that a strong temperature dependence is observed (Figure 1). Several factors can combine to produce such large effects.