Bottomhole Pressure Measurements Research Articles

Unified transient analysis (UTA) of production and shut-in data from hydraulic fractured horizontal wells

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). This study presents 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 A f k and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, it shows 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. • A unified transient analysis (UTA) is proposed to unify rate and pressure transient analysis of hydraulic fractured horizontal wells. • Inexpensive short-term bottom-hole pressure measurement is beneficial to calibrate long-term bottom-hole pressure. • Traditional log-log plot and square root of time plot may falsely interpret formation linear-flow as power-law behavior. • Hydraulic fracture surface area can be overestimated if only surface measurements are used.

Understanding Well Interference and Parent-Child Well Relationships With Liquid Molecular Chemical Tracer Technology

In an era where capital markets are hitting the brakes on funding the US shale sector, operators have increasingly pivoted from production growth to maximizing the rates of return via lower-cost wells. One of the major challenges of this new era is the determination of optimal stage and well spacing for a drilling area. For much of the US, the trend has been toward increased job size and rapid downspacing of infill or “child” wells. The unintended consequence of this trend has been an increase in fracture interference and excessive cross-well communication, which results in an overcapitalization of acreage and underperforming child wells as the drainage areas of wells overlap and compete for depleted resources. Within the SCOOP/STACK play, child wells completed in 2017/2018 have been half as productive as their 2015/2016 parent wells, a trend theorized to be directly related to negative fracture interactions. Determining an optimal spacing between parent and infill wells is not a straightforward endeavor. An ideal development strategy is not just about well spacing, as decisions in completion design can exacerbate issues stemming from tight spacing. For this multivariate problem, operators have attempted to use bottomhole pressure measurements to extrapolate fracture interference or to use large data sets in a “trial-and-error” approach to understand well interference behavior. These approaches have significant downsides, relying either on data sets of questionable value or on extrapolating data to and from wells with significantly different geological conditions. One operator in the SCOOP/STACK has attempted to understand well interference with chemical tracer technology. Using liquid molecular tracers, this operator achieved a quantified understanding of flow between parent/child wells with a high degree of confidence. This inexpensive technology has allowed the operator to experiment with well spacing and repressurization of parent wells. This, in turn, permits the rapid evaluation of mitigation techniques to optimize its field development strategy based on an accurate measurement of interwell fluid movement. Tracer Selection Two categories of chemical tracer are commonly used in conjunction with hydraulic fracturing operations: infused solid particulate tracers and liquid molecular tracers. While both tracer products have their strengths and weaknesses, liquid molecular tracers were chosen as a best practice in this study as they allow for quantification of the traced fluid phase, unlike infused solid particulate tracers.

Quantifying Total Apparent Hydraulic Fracture Conductivity and Its Significant Degradation from Systematic Bottomhole Pressure Measurements in Permian Wells

SummaryHydraulic fractures play a central role in the performance of multistage fractured horizontal wells (MFHWs) in tight and shale reservoirs. Fracture conductivity variations and connection quality between fractures and wellbore (i.e., choking skins) strongly affect well productivity. However, convincing and high-quality evaluations of hydraulic fractures for these reservoirs are rare in literature because quantifying fracture properties requires decoupling them from fracture geometry and formation properties, a difficult task in most field conditions. A data gathering and hypothesis testing program was implemented using six multifractured horizontal wells in a pad in the Delaware Basin to improve our ability to reliably forecast well performance. A systematic approach utilizing production, shut-ins, and bottomhole pressure measurements (BHP) was conducted and used to evaluate the apparent flow capacity of hydraulic fractures. Two independent techniques were used in the data analyses to characterize the hydraulic fractures; namely, pressure transients for individual wells and significant well-to-well interference signals. Both techniques render similar decline rate interpretations for the sets of fracture conductivity/permeability from analysis of the pressure data, but there is a large difference in the uncertainty of the estimated results from these two methods.The first method used a radial/linear flow regime in successive pressure buildups in three of the six wells. Simulations and theoretical analysis show that this flow regime allows decoupling fracture conductivity from fracture geometry and matrix properties. This flow regime yields the total apparent fracture conductivity (TAFC), which represents the lump sum effect of fracture conductivity. In addition, this technique characterizes the connection condition between the dominant fractures and borehole, which can be estimated from the early derivative horizontal line in pressure transient log-log diagnostic plots with minimum assumptions. Specifically, the estimated TAFC ranges from 1,140 to 1,630 md-ft at early time of well life to 525 to 855 md-ft after 100 to 139 days in production, or about a 45 to 61% reduction among these wells.The second method uses time-lag of pulse interference responses between an active and observation well. With assumptions of low, mid, and high values of fracture porosity, fracture compressibility, and fluid viscosity, characteristic fracture permeability can be estimated. Because of the large uncertainty related to the assumed fracture porosity and fracture compressibility, the pulse interference method is not likely to deliver the same certainty range as successive pressure buildups using the radial/linear flow regime.The results of this work provide a better understanding of the mechanisms of flow transport inside hydraulic fractures and at the connection between the hydraulic fractures and wellbore. The estimated TAFC and its significant decline help improve hydraulic fracturing designs and build representative reservoir models for more reliable well performance modeling and forecasting.

ВОССТАНОВЛЕНИЕ АБСОЛЮТНОЙ ПРОНИЦАЕМОСТИ ЗАЛЕЖИ УГЛЕВОДОРОДОВ С ВТОРИЧНЫМИ ФИЛЬТРАЦИОННО-ЕМКОСТНЫМИ СВОЙСТВАМИ С ИСПОЛЬЗОВАНИЕМ ВЕЙВЛЕТ-ПРЕОБРАЗОВАНИЙ

Due to depletion of hydrocarbon reserves in “traditional” porous reservoirs, it becomes necessary to study and evaluate the prospects for the development of reservoirs with secondary porosity–permeability properties (SPP). Permeability in reservoirs with SPP is described in a hydrodynamic simulator using a dualenvironment model represented as a set of porous blocks (matrix) separated by a system. One of the most important hydrodynamic model (HDM) parameters is the absolute reservoir permeability coefficient. However, recovery of the latter for reservoirs with SPP by standard methods is impossible. The purpose of this research is to restore a cube of the absolute permeability of a hydrocarbon reservoir with SPP using the wavelet transform method which accounts for the structure, to reproduce well dynamics in the HDM, and to analyze the applicability of the obtained maps when predicting distribution of productive zones. Wavelet-decomposition maps give a detailed description of the structural surface amplitude corresponding to the geological representation: the most productive zones are those with structural failures such as bending or dome. The downhole historical matching for bottom-hole pressure measurements and the dynamics of the work implemented using the wavelet transform method are performed in accordance with regulation requirements, which allow one to use a hydrodynamic model in the calculation of predictive options.

Discrete Fracture Modeling approach for simulating coupled thermo-hydro-mechanical effects in fractured reservoirs

We present a new formulation for modeling the coupled flow, thermal, and mechanical effects in real fractured subsurface formations. Natural fractures are represented explicitly as surfaces in contact with fluid between them. We use a finite volume method to discretize mass and heat conservation equations and a Galerkin finite element method to discretize mechanical equilibrium equations. We use the Nitsche approach to enforce fracture-contact constraints. The proposed formulation allows us to accurately evaluate fracture conductivity and volume change due to stress changes induced by variations in fluid pressure and temperature. To solve the resulting set of non-linear equations, we present a new sequentially implicit solution strategy based on a fixed-stress scheme for fractures, in addition to the established fully implicit approach. Our formulation is implemented within an existing general purpose research simulation platform that can account for complex physics such as multi-phase, multi-component flows. We show the convergence behavior of the sequential-implicit scheme for the problems considered.We demonstrate the utility of the formulation by considering the process of injecting cold water into a real fractured carbonate reservoir and evaluating the impact of resulting changes in formation pressure, temperature, and acting stresses on well bottom hole pressure measurements at the well. The goal of this application is to analyze the anomalously declining well pressure behavior observed during an actual short-term water-injection pilot operation towards informing the decision-making and preparation for potential large-scale waterflooding. We first perform a sensitivity analysis using a 2D conceptual model to assess key factors controlling the coupled effects for this problem: fracture and matrix properties, initial stress state, pressure- and temperature-induced stress changes and the propensity of fractures to slip, as well as Biot's coefficient. We then applied the framework on a 3D sector model of a fractured reservoir. We conclude that the observation was likely due to the substantial stress reduction caused by pressure and temperature changes, leading to slip events and a significant increase in fracture network conductivity near the injector. Thermal effects have less of an impact during the relatively brief pilot injection in this case but are expected to become important for long-term waterflooding.The application to a real waterflooding problem demonstrates the usefulness of the proposed thermo-hydro-mechanical framework for practical studies of real fractured reservoirs.

Комплексный анализ замеров забойного давления и продуктивности пластов многопластовых объектов в скважинах, оборудованных системами непрерывного мониторинга

Комплексный анализ замеров забойного давления и продуктивности пластов многопластовых объектов в скважинах, оборудованных системами непрерывного мониторинга

Improved Kick and Loss Detection and Attenuation in Managed Pressure Drilling by Utilizing Wired Drill Pipe

A model based method for kick and loss detection and attenuation in Managed Pressure Drilling is presented. The drilling system is modeled as a distributed parameter system combined with a reservoir flow equation containing reservoir pressure and the so-called productivity index as uncertain parameters. A swapping-based design for state and parameter estimation utilizing bottom-hole pressure measurements available via wired drill pipe is combined with a closed loop controller for kick and loss attenuation. The performance of the proposed method is compared to earlier results on kick attenuation in a simulation, showing significant improvement.

Operational Challenges and Monitoring of a Polymer Pilot, Matzen Field, Austria

Summary Four main areas of uncertainty can be described in polymer-injection projects: Are we able to deliver the polymer solutions at the required quality to the wellhead? Are we able to inject polymers at the required quantity and quality? Are we producing sufficient incremental oil? Are we able to separate and treat oil and water cost-effectively after polymer breakthrough? The monitoring program that was developed for the polymer-injection pilot aims to reduce the uncertainty and quickly identify operational difficulties, as described in the following: Polymer quality at the wellhead: The polymer concentration and viscosity of the “source” solution and injected polymer solution were measured at various locations in the surface facilities. A quality check of the delivered polymer (including a filter ratio test of the dissolved polymer) was performed, the biological activity monitored, iron content measured, and polymer solution investigated for “fish eyes.” The monitoring program enabled us to identify challenges related to shearing the polymers after changing the operating envelope, to identify problems related to biological activity, and to ensure data quality for interpretation of the pilot. Injectivity and degradation: Monitoring involved wellhead- and bottomhole-pressure measurements, repeated falloff tests, and visual observation of the polymer solutions in the well. The results showed the mobility reduction of the polymer solutions and an indication of induced fractures. Combining the various measurements led to identification of an operational issue—the injectivity decreased more than expected from polymer rheology and prepilot water-quality assessment. The reason was the combination of fines and small oil droplets existing in the injection water with polymer- and biological-generated mass that plugged the pores during injection. Incremental oil: Accurate measurement of the produced-water cut, especially for those wells producing at water cuts greater than 90%, is key for reporting accurate incremental oil. In addition, water salinity at the producing wells was measured, and a repeated tracer program was instituted. The results have been used to assess the reservoir architecture and incremental oil related to polymer injection. The challenges in the interpretation of the pilot conformance could be resolved by use of these data. Polymer, oil, water treatment: The surface facilities are monitored constantly for separation efficiency and plugging owing to back-produced polymers. Operating challenges are seen in all treatment steps for full-field polymer-injection implementation because of both oil/water separation and handling of the polymers in water-treatment facilities.

Evaluation of inter-well connectivity using well fluctuations and 4D seismic data

An integrated methodology is proposed to quantitatively evaluate interwell connectivity by uniting available data from the production and seismic domains, while simultaneously honouring reservoir geology. The Capacitance Model approach for interwell evaluation is selected initially to obtain prior understanding using well production and injection fluctuations. Then, to make proper use of 4D seismic data, we extend the newly developed “well2seis” technique to further predict the well-to-reservoir connectivity by correlating multiple seismic monitor surveys to the well behaviour data. Based on the prior information provided by the Capacitance Model, appropriate wells are selected to provide robust 4D seismic correlation. The final result is generated as a 3D attribute volume, which directly reveals spatial patterns of reservoir connectivity. The proposed methodology is firstly tested on a synthetic case, where it is shown that the well2seis correlation attribute can correctly identify key reservoir flow barriers and conduits. When applied to observed data from the Norne field, the pressure diffusion and fluid flow pathways from injectors to producers are detected, which are consistent with bottom-hole pressure measurements and observed sea water production breakthrough. We also discover a key fault barrier which was not considered in the reservoir model previously and successfully improves the history matching quality. The understanding of the reservoir connectivity is significantly improved compared to using conventional methods or the 4D seismic method independently.

Pressure-Transient Analysis of Bottomhole Pressure and Rate Measurements by Use of System-Identification Techniques

SummaryThis study presents a novel perspective on pressure-transient analysis (PTA) of downhole-pressure and flow-rate data by use of system-identification (SI) techniques as widely used in advanced process engineering. Key features of the paper are that it considers the classic PTA process from a system-theoretical perspective; derives the causal structure of the flow dynamics; proposes a method to deal with continuously varying pressure and flow-rate signals contaminated with correlated noise, which estimates physical reservoir parameters through a systematic matching procedure in the frequency domain; and can cope with arbitrary (i.e., not necessarily piecewise constant) flow-rate signals. To this end, the wellbore and the reservoir are modeled as two distinct two-port power-transmitting systems that are bilaterally coupled at their common boundary. This structure reveals that, from an SI perspective, the wellbore dynamics affect the bottomhole data as a feedback mechanism. Because of this feedback structure, it is necessary to use closed-loop SI techniques, and, because of the presence of sensor noise, the reservoir model cannot be identified solely from the bottomhole measurements. Therefore, an auxiliary signal is needed, for which we choose the surface flow rate, although other signals, such as the bottomhole temperature, could potentially also be used. Then a suitable closed-loop SI technique is the so-called two-stage method. The first stage of the algorithm removes the dynamic effects of the wellbore from the noisy data, and the second stage identifies the reservoir model in terms of rational polynomials. Thereafter, the usual physical reservoir parameters (e.g., averaged permeability and skin factor) are obtained through matching the results of the identified reservoir model and those of typical analytical reservoir models in the frequency domain, as an alternative to classic graphical or numerical type-curve analysis. The method does not rely on a piecewise constant approximation of the flow-rate signal, unlike other known PTA methods such as time-domain deconvolution. Six numerical experiments, by use of a synthetic data set, and one field example, by use of data from a real gas well, illustrate the key aspects of the proposed method.

Bottomhole Pressure Control During Drilling Operations in Gas-Dominant Wells

Summary To obtain an underbalanced pressure condition, nitrogen gas can be injected into the drillstring. Simultaneous injection of liquids and gases leads to a highly dynamic flow system. During pipe connections, pressure transients can cause the bottomhole pressure to rise above the pore pressure of the reservoir or fall below the reservoir collapse pressure. Migration of gas during pipe connection and inflow from the reservoir will also cause bottomhole pressure changes. This paper presents a methodology for controlling the bottomhole pressure during drilling operations in gas-dominant wells. The methodology incorporates a dynamic model of the well fluid flow and the well-reservoir interaction. Available control actions during the drilling process are the gas injection rate prior to the pipe connection and choke valve settings during the pipe connection. Measurement of the pump rates, pump pressures, choke pressure and the bottomhole pressure are also available to support the control actions. However, during pipe connections and in the event of transient signal failures, the bottomhole pressure measurements will be suppressed. The control methodology used is based on a nonlinear model predictive control system, which predicts the near-future behavior of the well, and uses these predictions to obtain the optimal choke settings. The model parameters are calibrated using measurements from the well to ensure that the model is suitable for the predictions. A field-based case with gas injection has been examined using this control methodology. The results indicate that model based control can be utilized in developing an automated and integrated pump rate and choke-control system for underbalanced drilling operations.

New Well-Testing Methods for Rod-Pumping Oil Wells—Case Studies

Summary A new well-testing method that provides high-resolution bottom-hole pressure (BHP) measurement has been developed for use with rod-pumping oilwell completions. This new well-testing technique is conducted by running a high-resolution downhole pressure gauge in a specially designed carrier assembly with the downhole pump. The gauge assembly is run on the rod string without pulling the completion packers or tubulars. With the new method, a down-hole pressure system is in place while the well is flowing during the entire well test. High-resolution downhole pressure data can then be recorded during all flow and shut-in periods of the well test, providing more accurate pressure data and enhanced capability for reservoir analysis. Traditional techniques use wireline-conveyed pressure gauges, tubing-conveyed pressure-recording devices, and surface pressure-monitoring systems with an advanced fluid-level measurement to record data from pumping well completions. These methods are limited in their ability to provide accurate test results when low-pressure conditions prevail. The new method allows operators of low-pressure oilwell completions to use advanced well-testanalysis software to analyze actual pressure data to obtain reservoir properties and quantify skin damage. Data can be acquired from many types of rod-pump completions, including wells with downhole gas separators. Excellent pressure resolution has been obtained from this new testing technique with either of two downhole assembly designs depending upon the completion configuration. The results and the ensuing well-test analyses in several pilot pumping wells will illustrate that the new process permits more flexibility in well testing and allows for greater accuracy and better interpretation of data in low-pressure rod-pumping oil wells.

Well-Productivity Improvement by Use of Rapid Overpressured Perforation Extension: Case History

Abstract This paper describes overbalanced perforating and surging operations as a pretreatment to hydraulic fracturing for the Romeo interval at Prudhoe Bay. Operation conditions are presented and discussed, as well as surface and bottomhole pressure measurements. Well productivity and the amount of proppant placed are compared to results in offset wells where the technique was not applied. The paper shows how the use of the technique allows placement of small, highly conductive fractures in intervals that were not previously considered fracturing candidates due to the close proximity to the gas/oil contact (GOC).The paper also shows pressure transient analysis affirming the technique as a stand-alone stimulation. It is shown that the use of extreme overbalanced perforating and surging treatments prior to hydraulic fracturing produces a substantial increase both in the success rate and the efficiency of the hydraulic fracturing operation and in the production rate of the wells that are pretreated. Finally, a comparison between pressure data and a new radial fracture propagation model shows a good match. The model demonstrates that high-energy treatment can significantly increase the extension and the height of the fracture; this was corroborated by downhole pressure measurements recorded during one overbalance treatment and by well logs. Introduction In 1990 an aggressive hydraulic fracture stimulation program began in the Prudhoe Bay Unit's Sadlerochit reservoir. This paper is limited to the ARCO-operated portion of the field or the Eastern Operating Area (EOA). North Slope wells, like offshore wellbores, are drilled from a central location. These extended reach wells present difficulties for hydraulic fracturing operations because of shear stresses associated with wellbores that do not align with one of the principal in-situ stresses. The fracturing campaign was highly successful and has resulted in an incremental oil rate of 180,000 barrels of oil per day (BOPD) from 1990 through1993 - Two hundred thirty-three wells were hydraulically fractured in the EOA, with a comparable number fractured in the Western Operating Area (WOA). The primary hydraulic fracture stimulation zones are the Romeo and the Zulu. Of these EOA wells, 34% were stimulated in the Romeo formation, 56% in the Zulu formation. Even though the zones are in the same reservoir there are significant differences requiring different hydraulic stimulation approaches. This paper addresses the more difficult to fracture Romeo interval by first describing the problem of Romeo formation fracturing followed by a discussion of the extreme overbalance (EOB) operations done at Prudhoe Bay. The impact of these pre-treatments is discussed on subsequent fracturing treatments and on the well productivity. Several case histories are presented that further illustrate the technique. Stimulation benefit of stand-alone extreme overbalanced perforating treatments is also investigated using bottomhole pressure data. Finally, fracture propagation model predictions of surface and bottomhole pressure are compared with surface and bottomhole pressure recorded during the EOB with fast-response pressure transducers. Formation Description. The Zulu is a clean sand several hundred feet thicken cased between large shales. These thick shales adjacent to the Zulu allow large fractures to be placed without fracturing out of zone. On the other hand, the lower Romeo sands are less continuous, less permeable, finer grained, and are thin sand/shale sequences.

A Methodology to Evaluate Regional Hydraulic Controls on Flow from Hydrocarbon Reservoirs into Overlying Aquifers: ABSTRACT

Because drilling, completion, and abandonment practices for oil and gas wells have improved over the past century, some older abandoned wells may be mechanically deficient or inadequately plugged, thus posing a risk of contamination to underground sources of drinking water. The risk of saltwater contamination of freshwater aquifers through inadequately plugged, abandoned wells increases if the hydraulic potential of the oil- and-gas-bearing brine formations is higher than that in the overlying freshwater aquifers. First, average regional potentiometric surfaces of aquifers and reservoirs are generated from aquifer water-level measurements and the conversion of bottom-hole pressure measurements from oil and gas reservoirs to hydraulic heads. Next, differences in hydraulic heads between aquifers and reservoirs are calculated to delineate regional residual areas of upward (positive) or downward (negative) hydraulic gradients. Third, locations of abandoned wells and class II injection wells are plotted relative to residuals to examine where water flooding, pressure maintenance, and saltwater disposal may cause or exacerbate the potential for upward flow. Three areas were used as case studies for testing the method. Positive residuals in the South Texas basin (informally defined to include the Val Verde basin, Maverick basin, part of the Rio Grande Salt basin, and the Austin Chalkmore » trend) result from natural geopressuring in formations deeper than 6000 ft, which are negligibly affected by class II injection wells. Positive residuals in the greater Permian basin (including the northwestern shelf, Delaware basin, part of the Palo Duro basin, Central Basin platform, Midland basin, southern shelf, and Fort Worth basin) may reflect injection for enhanced recovery in the west and natural hydrologic processes in the eastern shelf region. Residual surfaces for the San Juan basin indicate several areas with a natural potential for upward migration of brine.« less

Reliability and applicability of DSTs and bottomhole pressure measurements in Texas Gulf Coast Tertiary formations

Pressure data gathered from drillstem tests (DSTs) and bottomhole pressure measurements provide critical information toward formation and can be used for an assessment of prevailing pressure regimes and their influence on the migration potential of formation fluids. Reliability of such pressure data is an issue of major concern in reservoir engineering practice and can be established through an appropriate screening procedure.

Evaluation Of Bottomhole Treatment Pressure for Geothermal Well Hydraulic Fracture Stimulation

Summary The geothermal reservoir well stimulation program (GRWSP) group performed a large hydraulic fracture treatment in the well Baca 20, located in the Union Geothermal Co. of New Mexico Redondo Creek project area in north-central New Mexico. This is the highest temperature well in the world to be successfully fractured with proppant to date. The treatment involved use of a large cooling water prepad followed by a high viscosity fracturing fluid carrying sintered bauxite as the proppant. A nonproductive 240-ft [73-m] openhole interval, with a formation temperature of 520F [271C], was selected and isolated for the job. Poststimulation tests and analyses indicate a fracture was successfully created with a large vertical height near the wellbore. A number of fracture evaluation techniques were used to analyze the job, including some that are unique. Among these techniques were fracture mapping by monitoring the microseismic events caused by the fracture job, downhole treating pressure data analysis, temperature profiles, electric log surveys, production tests, and chemical tracer monitoring. The poststimulation fluid productivity of the treated interval was subcommercial, probably because of low formation permeability surrounding the artificially created fracture. Introduction The GRWSP, sponsored by the U.S. DOE, was initiated in Feb. 1979 to pursue industry interest in geothermal well stimulation work and to develop technical expertise in areas related to geothermal well stimulation activities. Republic Geothermal Inc. and its principal subcontractors (Santrol Products Inc., Maurer Engineering Inc., Ten-a Tek Inc., and Vetter Research) have completed seven full-scale field experiments to date. One experiment, performed on Oct. 5, 1981, is the Baca 20 well in New Mexico. The Baca reservoir lies within the Jemez Crater, Valles Caldera, and is defined by more than 20 wells completed to date in the Redondo Creek area by Union. The main reservoir, 4,000 to 6,000 ft [1220 to 1830 m] in thickness, is composed of volcanic tuffs with low permeability and a primary flow system of open fracture channels. In the Redondo Creek area, wells have encountered a high-temperature >500F [260C]) liquid-dominated geothermal reservoir, but several wells have not been of commercial capacity, primarily because they lacked productive natural fractures at the wellbore. Baca 20 is near several of the better production wells in the Redondo Creek area. The original Baca 20 hole drilled toward the southeast was nonproductive. The well was redrilled to the northeast and marginally non-commercial production was obtained. The production interval of 3,322 ft [1013 in] extended from 2,505 to 5,827 ft [764 to 1777 m] in depth. A long-term production test performed in 1980 resulted in a stabilized flow rate of about 56,000 lbm/hr [25 400 kg/h] with a 56% steam fraction and a wellhead pressure of 116 psig [800 kPa]. The calculated permeability-thickness product was approximately 3,000 md-ft [915 md-m]. The primary in-flow zone was located at a depth of about 4,000 ft [1220 m] with deeper zones probably supplying some fluids. Unique pressure data were obtained during the treatment. These bottomhole pressure measurements, along with other techniques, were used to evaluate the fracture treatment and the ability of fracture design models to predict results in this type reservoir. The large hydraulic fracture job, described in the next section, was intended to continue development of the high-temperature stimulation technology needed for geothermal applications and to create the high-conductivity flow channel needed to make Baca 20 a commercial well. Description of Stimulation Treatment Baca 20 was originally completed as shown in Fig. 1A with a 9 5/8-in. [24.5-cm] liner cemented at 2,505 ft [764 m] and a 7-in. [17.8-cm] slotted liner hung at 2,390 ft [729 m] with the shoe at 5,812 ft [1772 m]. The 7-in. [ 17.8-cm] slotted liner was pulled, lost circulation zones cured using cement plugs, and then a 7-in. [17.8-cm] blank liner was cemented in place at 4,880 ft [1488 m] to isolate the desired treatment interval. Since the fracture interval was to be from 4,880 to 5,120 ft [1488 to 1561 m], a sand plug was placed from 5,827 ft total depth to 5,400 ft [1777 to 1646 m] and then capped with cement to 5,120 ft [1561 m]. The recompletion is shown in Fig. 1B. This particular 240-ft [73-m] interval was chosen primarily because the best production in the area has been found in comparable intervals near the bottom of the Bandelier tuff and because of its high reservoir temperature (520F [271C]). JPT P. 829^

Hydrologic Evaluation of Industrial-Waste Injection at Mulberry, Florida: ABSTRACT

An injection well was completed in 1972 at a chemical plant at Mulberry, in central Florida, to inject highly acidic industrial waste into limestone. The plant produces sodium fluosilicate from the reaction of sodium chloride with fluosilicic acid, a byproduct of nearby phosphate processing plants. The resulting liquid waste, which is to be injected into the subsurface, has a high chloride content and a pH that is generally less than 2 and at times less than 1. The cased injection well is finished as a 6¼-in. open hole in limestone, from 4,040 to 4,984 ft below land surface. The injection-well annulus has two monitor wells, one open near the base of the Floridan aquifer from 1,254 to 1,264 ft, and the other open below the Floridan aquifer from 2,755 to 2,788 ft. Before injection tests were made, geophysical logs and a tracer test were run on the well. The radioactive-tracer test indicated that several permeable zones are exposed in the open hole. The native fluid, sampled prior to injection, and the waste fluid are markedly different in density, chloride content, and temperature. Two injection tests were run in the fall of 1972, using the waste fluid. The results of the first test were inconclusive because of inadequately controlled injection rates. During the second test, waste fluid was injected for 118 hours at 270 gpm and pressure readjustment was observed for 5 days. Injection pressure measured at the surface increased for the first 31 hours, and then decreased for the remainder of the injection period. The decrease in pressure after 31 hours is attributed to the net effect of reactions that occurred in the injection zone during the test. Dissolution of limestone by the low pH waste substantially increased the permeability of the rock adjacent to the well bore and increased the density and temperature of the injection fluid as it moved into the injection one. These changes coupled with the unavailability of direct bottomhole pressure measurements in the injection well and the lack of water-level measurements in an observation well finished in the injection zone complicated the evaluation of test results. As a result, only a general estimate of injection-zone transmissivity could be made. Where acidic wastes are to be injected into a carbonate zone, evaluation of natural conditions would be facilitated by the use of fresh water as the injection fluid during initial tests, and by measuring bottomhole pressure in the injection well and water levels in observation wells open to the injection zone. End_of_Article - Last_Page 1607------------

The Production Combination Tool-A New System for Production Monitoring

Data for diagnosing production problems or for zone-by-zone analysis of well performance are obtained with speed and safety using a combination production logging tool. As many as six items can be measured and recorded production logging tool. As many as six items can be measured and recorded sequentially in one trip, under essentially stable (or purposely varied) well conditions. Introduction Production logging is often used for diagnosis of Production logging is often used for diagnosis of production problems and sometimes for reservoir production problems and sometimes for reservoir analysis. To be valid, all measurements must be made under stabilized well conditions. In the past, the necessary information has been provided by a number of single-purpose through-tubing tools. In many cases the length of time required to make the various measurements raised doubt that the conditions remained constant throughout the survey. Moreover, the scope of application of production logging has been limited by the lack of a companion bottom-hole pressure measurement. pressure measurement. With the Production Combination Tool (PCT) the necessary information - flow rate, pressure, temperature, hole size, and fluid density, along with casing collar depths - is obtained sequentially in one trip in the hole. Usually only a few minutes are required for each measurement, so it can be assumed that uniform conditions prevail for the entire survey. A new technique for in-situ calibration of the flowmeter section establishes an accurate response curve for the particular fluids and casing size. particular fluids and casing size. When used with dynamic pressure control at the wellhead, the PCT makes it possible to obtain the measurements under normal production or injection conditions. (Or, if desired, well conditions can be changed and additional measurements made without the need to wait long periods for stabilization.) Zone-by-zone evaluation of initial production, as well as periodic reservoir auditing during the life of the well, can be done with a minimum of time, equipment, and surface data. Information for planning remedial procedures in workover wells is also provided. procedures in workover wells is also provided. The PCT Equipment The PCT is a combination of five different sensors and a casing collar locator (Fig. 1). The sensors are: continuous flowmeter, caliper, gradiomanometer, thermometer, and manometer. By means of a relay in the tool, controlled from the surface panel, any sensor may be selected. The corresponding property is recorded simultaneously with the casing collar log so that proper depth control is ensured. The various measurements are made sequentially in one trip in the hole, so a minimum time elapses between the different recordings. The principal advantage is that all necessary measurements are made in such a short time that the well producing conditions can be considered stable, and the different recordings are quasi-simultaneous. It is possible to change the producing conditions and monitor this change from the producing conditions and monitor this change from the surface through the various senors to obtain, in a very short time, information on the reservoir dynamics. The PCT is small in diameter (1 11/16 in.) so it can be lowered through the tubing against high pressure and flow to make dynamic measurements in the casing or open hole below the tubing shoe. The tool is centered in the fluid vein by spring centralizers. The tool ratings and specifications are summarized in Table 1. JPT P. 603

Practical Application of Interference Tests

Abstract This paper describes field application and calculation of an interference test in the North Anderson Ranch (Wolfcamp) field, Lea County, N. M. With the proper application of core and fluid analysis information in connection with bottom-hole pressure measurements, the drainage area of producing wells and the spacing requirement for an entire field can be calculated. Published formulas are used in the calculation. A modified 160 acre five-spot pattern was used in the field test whereby the center well as the observation well was surrounded by four producing wells. Bottom-hole pressures were measured continuously in all five wells during the first part of the test. The information was evaluated after the pre-determined amount of oil was produced. The test then was continued for the remainder of the month. Excellent agreement between calculated and measured drawdown was obtained, verifying the unsteady-state flow equations which have been developed and which are published in the literature. Introduction This paper describes the field application and calculation of an interference test in a reservoir in a Wolfcamp field in Lea County, N. M. It was the purpose of the test to determine the drainage area and spacing requirements for this reservoir. Well completion information indicated that each well location had experienced drainage prior to being drilled. When each well was completed it had a lower initial bottom-hole pressure than the preceding well, indicating some drainage, Furthermore, material balance calculations gave apparent drainage areas far in excess of the field-wide spacing rule of 40 acres/well. The test was undertaken to substantiate this behavior in order to avoid the drilling of unnecessary wells and to obtain 80-acre allowables for the field. Primary Development and Production History The North Anderson Ranch (Wolfcamp) field was discovered in May, 1958, with the completion of the well, Gulf Oil Corp. State 1-A. However, at that time it was not recognized as a new field. It was believed to be an extension to the Anderson Ranch Wolfcamp field, which was discovered in July, 1953. During 1958, two more wells were completed in the reservoir. Then in 1960, Union Oil Co. successfully completed its State No. 1–33 in the center of the 360-acre exploratory unit. This touched off an active development program and by the end of 1961 there were 11 wells producing from the Wolfcamp in the Subject area. During the same time interval, the production rate more than tripled from approximately 450 BOPD during 1959 to over 1,500 BOPD, corresponding to the 40-acre allowables for the wells (see Fig. 2). All wells were completed as flowing producers. By now, the field is producing at a rate of 2,375 BOPD from 16 wells and has a cumulative production of 1.8 million bbl. Six of the wells producing from the Wolfcamp in the North Anderson Ranch area are completed in more than one zone, although they are all in the Wolfcamp. The zones cannot be correlated with 100 per cent certainty and only the five wells incorporated in the subject test are definitely producing from the same Source of supply. This has been called the C Zone. The other wells are producing from the A and B zones. No communication has been found between the zones. JPT P. 249^

A Study of Anomalous Pressure Build-Up Behavior

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 44–50. Abstract In one field in South Texas, approximately 75 per cent of the pressure build-up results show a characteristic "hump" (i.e., the pressure builds up and then falls off) which makes interpretation by standard methods impossible. Correlation of size and time of hump with formation permeability, well productivity index, and method of completion led to the tentative conclusion that the humps were caused by segregation of gas and oil in the wellbore after closing-in. This conclusion was confirmed by performance of simple laboratory bubble-rise experiments, by theoretical bubble-rise time calculations, and by a detailed calculation of PVT behavior in the wellbore of a particular well on which accurate surface and bottom-hole pressure measurements were made. The hump behavior has since been found to occur in many other fields. The cause, however, is not the same in all cases. In some of these the hump is traceable to leaks in the tubing which allow influx of gas from the annulus after closing-in. In other cases the hump is traceable to leaks in the device separating pay horizons in dually completed wells. It is concluded that the recording of both surface and bottom-hole pressures is desirable in wells which show an anomalous build-up behavior. A number of field examples is discussed where use of both sets of measurements enables the cause for anomalous behavior to be found, and a reasonable interpretation of bottomhole pressure to be made. Introduction Theoretically the pressure build-up in an infinite reservoir should be a linear function of ln [(t + ?t) /?t] where t is the production time and ?t is the closed-in time. Some of the variations from this behavior are well known, such as the curved portion immediately after shut-in which results from after-production and skin effect, and the flattened end portion which results from boundary effects in a limited reservoir. The effect of stratified producing zones and irregular geometrical drainage patterns may also contribute unusual characteristics to build-ups.