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Collaborating Authors
Kabir, C. Shah
Summary Diagnostic fracture-injection testing (DFIT) has gained widespread usage in the evaluation of unconventional reservoirs. DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure-falloff test. This test is a pragmatic method of gaining critical reservoir information (e.g., the formation-parting pressure, fracture-closure pressure, and initial- reservoir pressure), leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, on the basis of the premise of a line-source well, we have shown that the early-time data can be represented by the square-root of time formulation, leading to the new modified Hall relation for the injection period.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Reservoir Characterization Begins at First Contact with the Drill Bit
Shayegi, Sara (Hess Corp.) | Kabir, C. Shah (Hess Corp.) | If, Flemming (COWI) | Christiansen, Soren (Hess Corporation) | Kosco, Ken (Hess Corporation) | Casasus-Bribian, Jaime (Hess Corporation) | Hasan, Abm Khalid (Blade Energy Partners) | Moos, Hasse (DONG Energy E&P)
Abstract Underbalanced drilling (UBD) offers a unique opportunity to estimate undamaged, in-situ formation properties upon first contact with the formation while drilling. This paper compares well-testing techniques developed for UBD with conventional methods. The reservoir flow rates in combination with flowing bottomhole pressures (BHP) acquired while drilling can be used to identify productive intervals and estimate dynamic reservoir properties. Unlike typical UBD projects where reservoir benefits are the primary focus, the driver for this mature field was overcoming the drilling problems associated with the wide reservoir pressure variability owing to nearby producers and injectors. UBD was piloted as a means to achieving the requisite lateral lengths for reserves capture and meeting production targets. Minimizing formation damage and characterizing the reservoir while drilling were added benefits. Several reservoir characterization methods based on rate-transient analysis (RTA) were used to perform well testing while drilling. Rate-Integral productivity index (RIPI) analysis uses the rate and pressure data acquired during drilling to determine whether additional holes drilled contributes and ascertain the relative quality of this rock. In the increasing boundary method, real-time rate and pressure data during drilling, circulating, and tripping allowed assessment of formation properties through history matching. Pressure buildup data was also available during trips because the concentric annuli allowed the pressure to be monitored below the downhole isolation valve. This data enabled the estimation of reservoir pressure and productivity index (PI) with a proxy vertical-well model for each productive interval drilled. These interpretation methods show close agreement in results and lend credence to the UBD-derived parameters. Introduction In UBD, the wellbore pressure is lower than the reservoir pressure. This wellbore condition allows formation fluids to flow into the wellbore during drilling. Proper instrumentation, data acquisition, and drilling procedures allow acquisition of data that are interpreted and analyzed to extract information about the reservoir. Reservoir characterization with UBD data is one of the benefits of drilling underbalanced. Unlike conventional overbalanced drilling or even managed-pressure drilling (MPD) with reduced overbalance margin, the UBD environment provides a unique opportunity to gather data that have the potential to provide important information about the reservoirs encountered during drilling. This real-time data provides the flexibility to adjust a drilling program still in progress. Subsequent well operations have the potential to damage the reservoirs that have been opened to the wellbore during drilling. Evaluating these reservoirs in an undamaged state (or as close to undamaged as possible) requires the capability to evaluate the data acquired during drilling. In essence a UBD operation allows transient-pressure testing and production logging while drilling. Based on rates and annular pressures gathered during drilling and mud circulation periods, the derived reservoir information allows determination of the in-situ undamaged production potential of the formation and fractures encountered. The early analysis done with rate and pressure data from underbalanced wells was simple PI and PI per unit length calculations in real time using calculators integrated into the data acquisition system (da Silva et al. 2007). More sophisticated methods using the PI concept emerged and one that has proven useful is RIPI by Suryanarayana et al. (2007), which is one of the methods used in this study.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Production of substantial fraction of CO2 in any hydrocarbon-gas stream poses a significant challenge in terms of separation and sequestration. Both environmental concerns and economic incentives provide the operators to search for safe, cost-effective ways of disposing CO2. This paper presents a case study where a pragmatic solution of CO2 separation at surface and its disposal in a saline aquifer occurs in close proximity to its source. A suite of both modern and classical analytical tools are used to understand production behavior of individual wells. This understanding is imperative because production volume is dictated by the ability to dispose of the associated CO2 volumes to honor the fault-activation pressure limit. The analytical tool kit comprising transient-PI, combined static and dynamic material-balance methods, rate-transient analysis, among others, paved the way for rapid assessment of both the producing gas reservoir and the saline aquifer receiving the CO2 stream. The use of real-time data allowed a comprehensive assessment of in-place volumes for the source gas and the capacity of the aquifer. Injection of supercritical CO2 suggests that the terminal aquifer pressure has been reached by encountering less-than-expected storage volume and owing to lowering of fracture-pressure gradient. On-time learning has allowed the asset team to search for alternative CO2 disposal solutions to ensure continuous gas production from this field. Introduction The merits of sequestering greenhouse gas have been discussed widely in the literature (IPCC, 2007; NETL, 2007). The capture and subsequent sequestering of CO2 has attracted a great deal of interest across multiple disciplines within the oil and gas industry, as well as power and allied industries. Saline aquifers present the most realistic option for sequestration. Other options, including abandoned oil and gas fields, are limited owing to the proximity to the source issue. Some studies (Flett et al. 2007) have probed the feasibility of separation of CO2 from a natural gas stream to allow processing in a liquefied-natural gas or LNG plant. Research in the past (Ennis-King and Paterson, 2003) has emphasized formation of a CO2 plume in a saline aquifer and the attendant mass transfer. Flow simulation studies showed that the gas/water relative-permeability hysterisis effect (Flett et al., 2004a, b) and trapping (Kumar et al. 2004) are plausible mechanisms for storage. Mineralization of rocks owing to formation of carbonic acid was postulated as yet another storage mechanism. However, the mineralization process is thought to be a very slow process requiring thousands of years (Bachu et al., 1994; Preuss et al., 2003). The Flett et al. (2007) study concluded that the migration of a CO2 plume takes a very long time to equilibrate and that most shales are capable of trapping it. Most of these studies focused on sandstones. In carbonates, experimental studies showed that the pore characteristics change with CO2 injection and that improved injectivity is tied to formation of preferential channels or wormholes (Izgec et al. 2008a). Although commercial simulators may be used in modeling CO2 sequestration, changes in rock properties owing to fluid-rock-CO2 interactions may be hard to capture without experimental data, as Izgec et al. (2008b) have shown. The study of Ehlig-Economides and Economides (2010a) suggested that injection of supercritical CO2 is tantamount to injecting liquid into a closed, liquid-filled saline aquifer. Using standard analytical treatment to model the behavior of such a system, they concluded that the volume of injected fluid cannot normally exceed 1% of pore space. The notion of a closed system generated a lot of discussion (Cavanagh et al., 2010; Ehlig-Economides and Economides, 2010b). Although the national energy technology laboratory (NETL) have reported (2011) a few worldwide CO2 injection projects, lack of engineering data in the public domain do not allow objective assessment.
- Asia (1.00)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- North America > Canada (0.89)
Summary Application of fast, simple and yet powerful analytic tools, capacitance-resistance models (CRMs), is demonstrated with four field examples. Most waterfloods lend themselves to this treatment. This spreadsheet-based tool is ideally suited for engineers who manage daily flood performance. We envision CRM application to precede any detailed full-field numerical modeling. We have selected field case studies in a way to demonstrate CRM capabilities in different settings: a tank representation of a field, its ability to determine connectivity between the producers and injectors, and understanding flood efficiencies for the entire field or a portion of a field. Significant insights about the flood performance over a short time period can be gained by estimating fractions of injected fluid being directed from an injector to various producers and the time taken for an injection signal to reach a producer. Injector-to-producer connectivity may be inferred directly during the course of error minimization. Because the method circumvents geologic modeling and saturation matching, it lends itself to frequent usage without intervention of expert modelers.
- North America > United States > Texas (1.00)
- North America > United States > California > Los Angeles County (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (25 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract This study expands upon the use of modified-Hall analysis to discern the characteristics of a high-permeability channel. Briefly, the modified-Hall plot uses three curves involving improved Hall-integral and the two derivatives, analytic and numeric. Ordinarily, the derivative curves overlay on the integral curve during matrix injection, but separates lower when fracturing occurs. This work presents a method to identify and characterize high-conductive layers or channels between injector and producer pairs with the modified-Hall analysis. The distance separating the integral and derivative curves provides the required information to quantify channel properties. A simple analytical solution is presented for transforming the separation distance into channel permeability-thickness product. The analytic derivative is based on the radial-flow-pattern assumption and the numeric derivative is correlated to the pressure response. Therefore, a comparison of these two curves reveals clues about the maturity of a waterflood at a given time. Several simulated examples verified the channel-property-estimation algorithm and identified the distinctive derivative signatures for channeling and fracturing situations. This methodology is also useful for identification of wormhole propagation during sand production in unconsolidated formations. Introduction The success of any waterflood depends largely upon the ability to bank oil for efficient sweep to occur, regardless of the mobility ratio. Presence of reservoir heterogeneity simply compounds the volumetric sweep issue. While heterogeneity can manifest in many forms, this study focuses on identifying and characterizing high-permeability streaks or high-conductive fractures providing the preferential flow path. Understanding the presence of such preferential flow conduits help manage a waterflood by pattern realignment, recompletion, among other measures to improve the volumetric sweep efficiency. Of course, the characterization of a thief zone can immensely aid any flow-simulation study attempting to explain premature breakthrough. Among the tools available for injection-well monitoring, the conventional Hall analysis (1963) is quite popular. Ordinarily, lack of its sensitivity has prompted others to offer improvements over the years. Some of the notable contributors include Buell et al. (1990), who suggested the use of both bottomhole injection pressure and reservoir pressure instead of the wellhead pressure alone, as used in the conventional Hall plot. Evaluation of the reservoir pressure from a slope-analysis method was offered by Silin et al. (2005a, 2005b). Ideally, the Hall method is suitable for either early injection period or during the post-breakthrough period, because the notion of single-reservoir pressure is entertained. More recently, Izgec and Kabir (2009) offered a new formulation of the Hall analysis. To that end, the development of an analytic derivative expression turns out to be much more discriminating for yielding the desired diagnostic clues. Ascertaining variable radial distance of the injection bank and pressure at the water/oil interface (pe) made the new formulation robust and suitable for prebreakthrough situations. That study also showed that pe practically becomes time invariant in postbreakthrough situation, suggesting applicability of the original Hall formulation. In this study we show that the Hall integral and its numerical derivative become parallel when a high-permeability conduit is intercepted, and their degree of separation is a measure of permeability-thickness product of the channel-dominated system. We also show that step-rate testing, ordinarily conducted to establish formation-parting pressure, can reveal clues about the contribution of additional layers owing to increased pressure. In fact, distinguishing fracturing from channeling is established by comparing and contrasting both the analytic and numeric derivatives when breakthrough occurs.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.47)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-209-P > Stag Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-15-L > Stag Field (0.99)
Abstract Increased tubinghead temperature with increased rate may induce pressure increase in the annuli for the trapped fluid. Managing annular-pressure buildup or APB for sustaining well deliverability is particularly crucial in subsea wells, which cannot be intervened easily. Ordinarily, a multistring casing design accommodates anomalous pressure rise from the standpoint of well integrity. However, management of day-to-day operations presents challenges when APB occurs. This study presents mechanistic models for understanding and mitigating APB during production. Specifically, by preserving mass, momentum, and energy in the wellbore we developed two approaches involving semisteady-state and transient formulations for estimating APB. The intrinsic idea is to mimic the physical process with minimal input parameters to estimate pressure buildup in the annuli. Our model formulation handles the mechanisms of fluid expansion and fluid influx/efflux quite rigorously. This approach appears quite sufficient because we account for most of the cases of APB encountered. Introduction Historically, production and reservoir engineers seldom probed the root causes of APB, perhaps because tubular design with implicit APB control has been in the domain of drilling engineers. But the advent of continuous monitoring of pressure and temperature at the well bottom, tubinghead, and annuli presents the opportunity for real-time production and reservoir management within the safe operating limits of the system. Pressures measured at the tubinghead and bottomhole with the corresponding flow rate are the most sought after entities in production-engineering calculations; rate validation in integrated asset modeling is a case in point. In contrast, temperature measurements have not found routine usage, but are gaining increased attention in connection with transient-pressure testing (Sui et al. 2008, Duru and Horne 2008, Izgec et al. 2007, Hasan et al. 2005, Kabir et al. 1996), downhole flow profiling (Wang et al. 2008, Nath et al. 2007, Johnson et al. 2006, Ouyang and Belanger 2006), and flow-rate estimation (Izgec et al. 2008, Kabir et al. 2008). This paper shows that both pressure and temperature responses at the tubinghead and annuli are strongly related to flow rates and that these measured entities can be used to alert the operator of possible APB. Naturally, clarity in understanding interrelationship of wellhead temperature with flow rate and pressure is imperative for sustaining long-term wellhead deliverability without compromising well integrity. Fluid production in a typical production string influences pressures in production and surface casings. Generally speaking, only the shallowest casings are cemented to the top, whereas the others, cemented at the bottom, contain mostly drilling fluid. Producing fluids in the tubing string transmit heat to the liquid-filled annuli, thereby triggering pressure increase. APB is not just associated with fluid production; fluid circulation during drilling may also induce the same, as reported by Pattillo et al. (2006). Accessible wellheads in typical land and offshore dry-tree wells allow the operator to monitor and bleed off all annuli as needed. However, subsea wells present serious logistical difficulties for managing APB. Predictably the stakes are high in high-pressure, high-temperature (HPHT) wells and those that are completed in a deepwater environment, where intervention costs are prohibitive. High flow rates simply exacerbate the APB issue because of the associated high energy that the fluids bring to surface.
- Asia (0.68)
- North America > United States > Texas (0.28)
Summary This paper presents an analytic model for computing the wellbore-fluid-temperature profile for steady fluid flow. Although wells with a constant-deviation angle can be handled with existing analytic models, complex well architectures demand rigorous treatment. For example, changing geothermal-temperature-gradient and deepwater wells present significant challenges. Additionally, available analytic models rarely provide calculation methods for various required thermal parameters, such as the Joule-Thompson (J-T) coefficient and fluid expansivity. The approach taken in this study entails dividing the wellbore into many sections of uniform thermal properties and deviation angle. The governing differential equation is solved for each section, with fluid temperature from the prior section as the boundary condition. This piecewise approach makes the model versatile, allowing step-by-step calculation of fluid temperature for the entire wellbore. We present simple, thermodynamically sound approaches for estimating thermal parameters. Success is indicated when performance of the proposed model is compared with data from three wells, producing two-phase gas/oil mixture, single-phase oil, and single-phase gas. Sensitivity of the estimated fluid temperatures to various thermal properties is also examined with our model. Overall, the effects of the J-T coefficient and liquid expansivity are found to be significant. Introduction Modeling fluid-temperature and density profiles in wellbores is crucial for the design of production tubulars and artificial-lift systems, gathering pressure data for real-time reservoir management, and estimating flow rates from multiple producing horizons with distributed-temperature sensors. Significant advances have occurred in wellbore-fluid-temperature modeling since the pioneering work of Ramey (1962). Ramey's work addressed single-phase flowing-fluid temperature in a line-source well. In this regard, models of Alves et al. (1992), Sagar et al. (1991), and Hasan and Kabir (1994) are worthy of note. In particular, these models extended application to two-phase flows. Yet, the available analytic models are inadequate for direct application to modern directional wells that traverse formation with significantly varying thermal properties with multiple changes in deviation angles. In such cases, even the simple task of estimating geothermal temperature as a function of measured depth (MD) becomes nontrivial. Obviously, geothermal gradient strongly influences heat loss of wellbore fluids, requiring careful piecewise computation. The solution presented in this paper addresses these issues and lends itself to user-friendly spreadsheet computations, if one so chooses.
Abstract This study presents a robust model for two-phase flow in geothermal wells using the drift-flux approach. For estimating the static head, we use a single expression for liquid holdup, with flow-pattern-dependent values for flow parameter and rise velocity that gradually changes near the transition boundaries to avoid discontinuity in the estimated gradients. Frictional and kinetic heads are estimated with the simple homogeneous modeling approach. As the geothermal fluids ascend up the well, loss of both momentum and heat occur. The consequent pressure loss often leads to flashing and increase in steam fraction (quality) despite heat loss. Accurate estimation of heat loss, which leads to significant changes in fluid properties influencing pressure-drop is, therefore, important in modeling flow in geothermal wells. Heat transfer from the wellbore fluid to the surrounding formation is rigorously modeled by treating the wellbore as a heat sink of finite radius in an infinite-acting medium (formation) and accounting for the resistances to heat transfer offered by various elements of the wellbore. We present a comparative study involving the new model and those that are often used for geothermal wells. These models include those of Ansari et al., Orkiszewski, Hagedorn and Brown, Beggs and Brill, and the homogeneous model. The main ingredient of this study entails the use of a small but reliable dataset. Statistical analyses suggest that all the models behave similarly, although the proposed model offers marginally greater accuracy and simplicity of use. Uncertainty of performance appears to depend upon the quality of data input, rather than the model characteristics. Introduction Historically, pressure-traverse computation in geothermal wellbores followed a trend similar to that in wells producing hydrocarbons. This similarity is appreciated by noting that all the principal flow regimes, bubbly, slug, churn, and annular, are common to both systems. Some of the authors of early studies adopted a hybrid approach; that is, the slip between steam and water phases is computed with a different model in each flow regime. One potential difficulty of this approach is that the transition between the flow regimes may not be smooth, thereby triggering discontinuity. The early studies of Gould (1974), Chierici et al. (1981), Ambastha and Gudmundsson (1986a, 1986b), Chadha et al. (1993), among others, fall into the hybrid-approach category. A few authors, such as Upadhayay et al. (1977), used different models in their entirety to find the one most reliable. Orkiszewski's correlation (1967) appeared to have an edge in their study. In a more recent study, Acuña and Arcedera (2005) expressed a similar sentiment while discussing one field example. However, this view is not universal as Tanaka and Nishi (1988) showed in a study with 16 wells, containing varying amounts of CO2. Despite reporting comparative studies, most authors dealt with a very few wells, thereby leading to an important question: is the number of field tests sufficient to draw statistically significant conclusions with regard to superiority of one model over any other? To compound the problem, the dataset were incomplete; that is, both bottomhole temperature (BHT) and geothermal gradient went often unreported. Any comparative study involving models' relative performance is akin to the one used extensively in the petroleum literature. However, the number of wells in the petroleum industry dwarfs those that are available in geothermal production, thereby posing challenges in identifying reliable models for pressure-traverse computation.
Abstract Interwell connectivity is a key issue in any field development planning, especially when secondary and tertiary recovery methods are contemplated. Stakes are particularly high in deepwater and other costly environments where the well count largely dictates project economics. Traditional approaches to discerning reservoir compartments include fluid PVT properties, geochemical fingerprints, tracer testing, and transient-pressure testing. While fluids may provide clues about reservoir connectivity or lack thereof, they cannot tell us about the degree of connectivity between wells. In contrast, pulse testing may provide the necessary information, but the interwell permeability so estimated is skewed toward the observation well, and therefore may not be entirely satisfactory. This study presents an alternative method for establishing interwell connectivity involving production and injection wells. We show that capacitance-resistive modeling (CRM) is a viable alternative to solving transient-flow problems. Equivalence of streamline simulations and CRM is established for fractional flow directed at each producer. We also showed that one can discern connectivity between the injector and producers in an inverted-five-spot pattern and in channelized reservoirs, with limited injection in prebreakthrough scenarios. In closed systems, even low-signal quality may suffice for characterization, provided reasonable injection perturbation exists. Excessive voidage appears to be a nonissue as far as signal propagation is concerned. Introduction Reservoir connectivity between wells governs field development, particularly when contemplating secondary and tertiary floods. Principally, we have indirect and direct methods for establishing reservoir connectivity amongst wells. Although fluid analyses, such as PVT properties and geochemical fingerprinting serve the first-order purpose; however, no quantitative measure emerges when well-to-well connectivity exists. Some of the useful studies that appear in the literature in this context are presented by Smalley et al. (1994), Westrich et al. (1999), and Kaufman et al. (2000, 2002), among others. Collectively fluids, in general, and the oft-used fault/seal analysis fall into the category of indirect methods. Amongst direct methods, tracer and transient testing offer the opportunity to quantify reservoir connectivity. Tracer tests provide breakthrough time as a measure of connectivity, besides giving clues about reservoir heterogeneity and sweep efficiencies. For instance, Ohno et al. (1987) showed successful applications of both flow-simulation model and analytic technique proposed by Abbaszadeh-Dehghani and Brigham (1984) for a field example. Brigham and Abbaszadeh-Dehghani (1987) provide a comprehensive review of tracer testing. Reservoir continuity inferences have also been made by combined pressure-buildup testing and reservoir geology (de la Combe et al. 2005; Matthäi et al. 1998), to name a few. However, only transient-pressure tests involving pressure pulses, generated by carefully designed rate perturbations, provide quantitative information about interwell connectivity. Among the plethora of publications in this regard, the studies of Kamal (1979), Dinges and Ogbe (1988), and Ogbe and Brigham (1989) are worthy of note. Execution of pulse tests may be demanding because of large interwell distances, coupled with low-rock permeability and high-system compressibility in a given setting. Even where favorable conditions exist, costs and logistics of conducting those tests for multiple wells may be an impediment for routine applications.
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- Overview (0.68)
- Research Report > Experimental Study (0.68)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (3 more...)
Summary This work presents a complete reformulation of the Hall method involving both pre- and post-breakthrough situations. Two approaches involving both transient and pseudosteady-state methods produced very similar solutions, which were verified with the results of coupled geomechanical/fluid-flow simulations. The new formulations allow tracking the expanding water-bank radius from inception to breakthrough. Pressure of this bank at the water/oil interface is evaluated at every timestep, thereby allowing continuous update of the ‘external pressure’ in Hall's formulation. We show that Hall's formulation is a particular case of the proposed approach. Several simulated and field examples demonstrate the value of reformulated Hall analysis. Because Hall's formulation involves an integral, the resultant signature, by nature, is insensitive in revealing clues about subtle changes that may occur during formation fracturing or plugging. We observed that the derivative of the modified-Hall integral, obtained analytically, provides definitive signatures about fracturing or plugging. The new interpretation approach is particularly suitable for projects at the inception of flooding. Mature projects can benefit equally from the new tool. Perhaps the biggest appeal of the proposed tool lies in the green fields where real-time data are readily available. Introduction Significant advances have been made in recording, transmitting, filtering, and interpreting real-time production data. However, data interpretation from injection wells has not gained as much attention. Traditional water-injection well evaluation involves pressure-transient analysis, which predictably improved over the years, as testified by the contributions from Hazebtoek et al. 1958; Kazemi et al. 1972; Marrill et al. 1974; Sosa et al. 1981; Abbaszadeh and Kamal 1989; Yeh and Agarwal 1989; and Bratvold and Horne 1990. Falloff analysis allows estimation of permeability, skin, and drainage-area pressure. Because formation parting is quite common, van den Hoek (2005) presented a method for discerning shrinkage of fracture height or length from falloff tests. While great strides have been made in interpreting falloff tests, Hall (1963) plot appears to be one of the few tools available for ongoing performance monitoring. Others have attempted modifications of the Hall plot by introducing the use of bottomhole-flowing and reservoir pressures (Buell et al. 1990) or evaluating the reservoir pressure from a slope-analysis method (Silin et al. 2005a, 2005b). Ideally, the Hall method is suitable for either the early injection period or during the post-breakthrough period because the notion of single reservoir pressure is entertained. Both reciprocal-injectivity index, or RII (Hearn 1983; Abou-Sayed et al. 2007), and evolving skin (Zhu and Hill 1998) are other alternatives to monitoring real-time well performance. This study presents a new formulation of the Hall analysis. To that end, the development of an analytic derivative expression turns out to be much more discriminating for yielding the desired diagnostic clues. Ascertaining the variable radial distance of the injection bank and pressure at the water/oil interface (pe) makes the new formulation robust and suitable for prebreakthrough situation. Our study shows that pe practically becomes time invariant in postbreakthrough situation, suggesting applicability of the original Hall formulation.
- North America > United States > California (0.28)
- North America > United States > Texas (0.28)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)