Shut-in Period Research Articles

Inferring Interwell Connectivity from Well Bottomhole-Pressure Fluctuations in Waterfloods

SummaryThis paper presents a new procedure to determine interwell connectivity in a reservoir on the basis of fluctuations of bottomhole pressure of both injectors and producers in a waterflood. The method uses a constrained multivariate linear-regression (MLR) analysis to obtain information about permeability trends, channels, and barriers.Previous authors applied the same analysis to injection and production rates to infer connectivity between wells. In order to obtain good results, however, they applied various diffusivity filters to the flow-rate data to account for the time lags and the attenuation. This was a tedious process that requires subjective judgment. Shut-in periods in the data, usually unavoidable when a large number of data points were used, created significant errors in the results and were often eliminated from the analysis.This new method yielded better results compared with the results obtained when production data were used. Its advantages include: (1) no diffusivity filters needed for the analysis, (2) minimal number of data points required to obtain good results, (3) and flexible plan to collect data because all constraints can be controlled at the surface. The new procedure was tested by use of a numerical reservoir simulator. Thus, different cases were run on two fields, one with five injectors and four producers and the other with 25 injectors and 16 producers.For a large waterflood system, multiple wells are present and most of them are active at the same time. In this case, pulse tests or interference tests between two wells are difficult to conduct because the signal can be distorted by other active wells in the reservoir. In the proposed method, interwell connectivity can be obtained quantitatively from multiwell pressure fluctuations without running interference tests.

Simplified graphical correlation for determining flow rate in tight gas wells in the Sulige gas field

The Sulige tight gas reservoir is characterized by low-pressure, low-permeability and low-abundance. During production, gas flow rate and reservoir pressure decrease sharply; and in the shut-in period, reservoir pressure builds up slowly. Many conventional methods, such as the indicative curve method, systematic analysis method and numerical simulation, are not applicable to determining an appropriate gas flow rate. Static data and dynamic performance show permeability capacity, kh is the most sensitive factor influencing well productivity, so criteria based on kh were proposed to classify vertical wells. All gas wells were classified into 4 groups. A multi-objective fuzzy optimization method, in which dimensionless gas flow rate, period of stable production, and recovery at the end of the stable production period were selected as optimizing objectives, was established to determine the reasonable range of gas flow rate. In this method, membership functions of above-mentioned optimizing factors and their weights were given. Moreover, to simplify calculation and facilitate field use, a simplified graphical illustration (or correlation) was given for the four classes of wells. Case study illustrates the applicability of the proposed method and graphical correlation, and an increase in cumulative gas production up to 37% is achieved and the well can produce at a constant flow rate for a long time.

Reduction of Oil and Gas Coning Effects by Production Cycling and Horizontal Wells

This article investigates by simulation, coning mitigation during oil production from thin oil rim reservoirs using horizontal wells and production cycling. Production cycling is an operating technique in which the well is produced and then shut in for periods of time. During the shut-in periods, the cone reduces. This work suggests that production cycling delays water breakthrough. However, once breakthrough occurs, the well must be put on continuous production due to difficulties in unloading the wellbore and with the assistance of gas lift.

Interference well testing—variable fluid flow rate

At present when conducting an interference well test a constant flow rate (at the 'active' well) is utilized and the type-curve matching technique (where only 2–3 values of pressure drops are matched) is used to estimate the porosity–total compressibility product and formation permeability. For oil and geothermal reservoirs with low formation permeability the duration of the test may require a long period of time and it can be difficult to maintain a constant flow rate. The qualitative term 'long' period of time means that (at a given distance between the 'active' and 'observational' well) more test time (for low permeability formations) is needed to obtain tangible pressure drops in the 'observational' well. In this study we present working equations which will allow us to process field data when the flow rate at the 'active' well is a function of time. The shut-in period is also considered. A new method of field data processing, where all measured pressure drops are utilized, is proposed. The suggested method allows us to make use of the statistical theory to obtain error estimates on the regression parameters. It is also shown that when high precision (resolution) pressure gauges are employed the pressure time derivative equations can be used for the determination of formation hydraulic diffusivity. An example is presented to demonstrate the data processing procedure.

Overview: Gas Production Technology (November 2007)

For this feature, I have chosen three excellent papers that highlight the complex, but very common tendency of gas wells to "load up." Given the explosive growth in new low-rate gas completions and the persistent move of all older high-rate completions toward the same condition, this topic seemed fit for a little more attention. Although not specifically addressed in these papers, the recent widespread use of very long (or thick), multihydraulically fractured completions intensifies these problems. If you think you do not have a well with a liquid-loading issue, you probably have not looked hard enough. Each of these papers addresses the issue from a different viewpoint. One uses video logging to "see" what is happening downhole, while another uses truly remarkable integrated transient wellbore and reservoir-simulation tools to predict mathematically the same behaviors observed in the first. The other paper stakes out a middle position of using comparatively simple analytical models to predict the exact location of a standing liquid level within a gas-producing section. The video-logging paper describes a series of production logs run in several horizontal wells. In the best spirit of data collection and research, the results were far from the expected outcome and revealed the predrill assumption of no potential loading problems to be incorrect. Also, the authors specifically put to rest that long-debated question of what happens to liquid and solids accumulations in horizontal wells with a toe-up trajectory. The paper on modeling the liquid-loading process builds on and complements N. Dousi et al. 2006 "Numerical and Analytical Modeling of the Gas-Well Liquid-Loading Process" [SPE Production & Operations21(4): 475–482 (SPE 95282-PA)]. In both papers, water loading up the wellbore is studied in detail. They both predict a "metastable" flow condition in wells that cannot lift all the liquid but have sufficient liquid injectivity (into the producing zones) to not die completely. This wellbore condition is now attributed to significant formation damage and well-performance deterioration after shut-in periods. The integrated-wellbore/reservoir-model paper takes the subject even further, with an exhaustive transient mathematical treatment of the loadup process. Coupling a reservoir simulator with a time-dependent wellbore model, the authors were able to prove that mathematical models can match an erratic production profile, although that is rarely the objective of the typical modeler. Whatever your mathematical inclination, one of these offerings should help you gain a greater appreciation of the complex process of liquid loadup in wellbores. Gas Production Technology additional reading available at the SPE eLibrary: www.spe.org SPE 107870 "Analysis of Condensate Buildup and Flow Impairment of Retrograde Gases in Fissured Reservoirs" by H. Ayala, Pennsylvania State University, et al. SPE 107169 "Controls on Water Cresting in High-Productivity Horizontal Gas Wells" by R.P. Sech, SPE, Imperial College London, et al. SPE 107274 "Economic Viability of Gas-to-Liquid Technology" by Ali A. Garrouch, SPE, Kuwait University SPE 101497 "Applications of Acoustic Liquid-Level Measurements in Gas Wells" by J.N. McCoy, Echometer Company, et al.

Boundary Effects and Depth of Investigation From Long Buildups Following Short Flow Tests

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102699, "Boundary Effects and Depth of Investigation From Long Buildups Following Short Flow Tests," by L. Larsen, SPE, Statoil ASA, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24-27 September. Slug tests and other tests for which the buildup period greatly exceeds the flow period have been addressed in the literature by several authors over the last 30 years. This paper examines such tests to investigate the possibility of drawing conclusions about boundary effects. Introduction Although some of the standard techniques used to analyze slug tests can, in principle, detect boundaries at distances far beyond the distance affected by the flow, special approaches must be used to avoid the need for a highly accurate estimate of the initial formation pressure. Often, the pressure change relative to the initial formation pressure is used in analyses. For cases with small pressure changes at the end of the buildup, the characteristics of the pressure response are highly sensitive to the choice of formation pressure, making it difficult to distinguish boundary effects from effects of erroneous input. Straightforward derivative methods can be used to analyze buildup data following short flow tests without the initial formation pressure as a key input parameter. The full-length paper details the use of two approaches to analyze the data and reduce the uncertainty in the results. The methods use different data sets, but both require high-quality data to reduce uncertainty and maximize the depth of investigation. Results from well-known derivative methods deviate to some extent from expected results. The derivative approach does not work for all types of models in a theoretical sense, but it does work for all cases of practical interest. The results apply to any data set with a shut-in period that is much longer than the flow period—for instance, with days of flow and months of shut-in data. Gauge resolution is particularly important in analyses to identify effects of distant boundaries. Noise in the pressure data and disturbances in the data from wellbore effects also are critical. For successful analysis, the method is highly important when late-buildup data that approach the initial pressure are used. Pressure differences relative to an estimated initial pressure normally are used in analyses, and such analyses can be highly sensitive to the accuracy of this parameter. Because the initial pressure is not known exactly, alternative methods that use only measured data are advocated here. When drawing conclusions about observed boundary effects and the radius of investigation in general with or without boundary effects, the pressure derivitives become critical. A high estimate of the initial pressure in a standard slug-test analysis can cause late data to suggest the presence of a no-flow boundary. A low estimate of the initial pressure in such an analysis can cause late data to suggest the presence of a constant-pressure boundary. The deviating trend also can be taken as an indication of an erroneous value for the initial pressure, but only if it is known that no boundary effects exist.

Determination of formation temperatures from temperature logs in deep boreholes: comparison of three methods

The most important data on the thermal regime of the Earth's interior come from temperature measurements in deep boreholes. The drilling process greatly alters the temperature field of formations surrounding the wellbore. The temperature change is affected by many factors and the exact determination of formation temperature at any depth requires a certain length of shut-in time. In theory this shut-in time is infinitely long. There is, however, a practical limit to the time required for the difference in the temperature between the well wall and surrounding reservoir to become a negligible quantity. In this paper, we conducted a comparison of three methods of predicting the undisturbed formation temperatures from shut-in temperature logs in deep wells. Long-term temperature surveys in five wells were selected to estimate the formation temperatures and to compare measured and predicted transient formation temperatures. It was found that the best agreement is observed with values calculated by the ‘three-point method’ and measured during shut-in period transient temperatures.

Technology Update: Real-Time Fluid Tracking Optimizes Treatment Design, Improves Strategy

Collecting complete wellbore-temperature profiles during the placement of stimulation and diversion fluids has opened a new window to understanding and modifying matrix-stimulation, fracturing, and conformance treatments. Rapidly collected temperature profiles can identify precisely where fluids are entering the formation, allowing real-time optimization of the treatment through on-the-fly modification of the planned program. Such knowledge is necessary to improve stimulation-fluid placement across the entire treatment interval. The Halliburton StimWatch service identifies stimulation-fluid placement on the basis of changes in fluid properties that introduce variations in temperature gradients as the fluid moves inside the wellbore. This type of analysis provides a detailed understanding of the quality of treatment as applied to the designated intervals through a quantitative assessment of downhole flow rates. Monitoring Benefits Historically, it has been difficult to evaluate the placement of stimulation fluids during a multizone treatment in real time. As a result, the zonal volume of injected fluid is based completely on geological-data interpretation; prejob fluid-placement simulators provide only a theoretical prediction of the injection profile. Unknown and unpredictable downhole events occur during stimulation treatments and can have significant impact on treatment results. To achieve successful stimulation treatments, it is important to obtain the following information throughout the job:Injection profile—which zones are being treated effectively and which zones are not being treated.Effectiveness of a diversion process.Status of squeezed zones.Location of natural fractures. Service Description The StimWatch service follows the treatment as it progresses downhole, monitoring distributed temperature profiles obtained by use of the fiber-optic OptoLog Distributed Temperature Sensing (DTS) system. As changes in wellbore temperature are caused by the injection process, this information is converted into downhole injection profiles for a qualitative indicator of fluid distribution across the pay interval. This is performed without the need for shut-in periods or extensive preconditioning of the wellbore. The DTS fiber-optic-cable assembly can be deployed in a permanent or retrievable configuration. The assembly can be strapped to the completion casing or production tubing as a permanent installation. For retrievable scenarios in horizontal wells, coiled tubing can be used to position the assembly across the perforated interval.

Techbits: Refracturing in Low-Permeability Reservoirs

A recent Applied Technology Workshop (ATW) held in San Antonio, Texas, "Refracturing in Low-Permeability Reservoirs," explored refracturing techniques and overall reservoir effects. The technical agenda was divided into eight segments: keynote, candidate recognition, rock mechanics, refracturing design, economics, case studies, refracturing unconventional reservoirs, and poster sessions. Kicking off the ATW was Chris Wright, President of Pinnacle Technologies, who brought participants up to date on where and how this domain surfaced, the various methods of candidate selection, and several brief case histories. While the technique of refracturing wells began in the 1940s, only a small number of wells have actually been refractured. The industry's tendency to refracture poor-quality wells has led to a perception that the technique of refracturing may not be successful. There may be as much as 10 Tcf of proved developed nonproducing gas reserves available by means of refracturing. The candidate selection process has improved significantly over the past few years, leading to better understanding and improved results. Various formations have responded to larger fractures, water fractures, low-gel-load fractures, and other methods. The data must be gathered and analyzed and best practices employed to optimize the refracturing design. Candidate Recognition Three presentations addressed selection of candidate reservoirs for refracturing. In a session titled "GIS Technology for Refrac Candidate Selection: Process and Example," BJ Services Applied Geoscience Manager Randy LaFollette described how a Geographical Information System (GIS) is used in the candidate selection process. The methodology is statistical, combining pattern recognition from aerial distribution of production performance and computational analyses/algorithms to provide short lists of refracture candidates. Individual well review occurs only on the "short list" wells as the last step before refracture treatments. A case history was used to explain workflow. West Virginia U. Professor Shahab Mohaghegh explained candidate selection methodology using virtual intelligence in a session titled "Restimulation Candidate Selection in Tight Formations." The process moves from field review to well-by-well review. This methodology attempts to merge a comprehensive production data set and analyze the data with reduced subjectivity while addressing the entire reservoir capability within reasonable geographic distance. The methodology is statistical and integrates several production-data-analysis techniques (e.g., type curve/dynamic contact angle). Case histories were discussed at the end of the presentation. In "A New Refracture Candidate Diagnostic Test Determines Reservoir Properties and Identifies Existing Conductive Damaged Fracture," Halliburton Rocky Mountain Tech Team member David Craig discussed a diagnostic test to determine refracturing candidates on both a well-by-well and an interval-by-interval basis. The test requires a short injection above fracture-initiation pressure and an extended shut-in period with the pressure falloff recorded. The test has both qualitative (identify existing fracture damage) and quantitative (permeability, current reservoir pressure, current fracture properties) objectives.

Laboratory Investigation of Enhanced Light-Oil Recovery By CO/Flue Gas Huff-n-Puff Process

Abstract This paper focuses on phase behaviour measurements with reservoir oil-CO2 mixtures and on coreflooding tests in the huffn- puff mode to characterize the system, determine the influential mechanisms, and supply data for simulation of the field implementation. The results indicate that significant amounts of CO2 could dissolve in the oil, which caused oil swelling and viscosity reduction. During the puff cycle, the oil retained CO2 preferentially to methane; thus, the beneficial swelling and viscosity effects were maintained over an extended portion of this cycle. Corefloods were performed to investigate the effect of waterflood residual oil saturation and injection gas composition (CO2 and enriched flue gas) on oil recovery. Incremental oil recovery was observed to be sensitive to waterflood residual oil saturation and to the process application scheme. Coreflooding results suggest that the huff-n-puff process may be more suitable to oil-wet than water-wet reservoirs. Introduction Various technologies have been applied in tertiary oil recovery processes, such as gas miscible/immiscible injection and chemical flooding. Among these enhanced oil recovery (EOR) methods, the huff-n-puff process has been reported to be economic at an oil price of less than US$20/STB and CO2 costs of US$40/ton(1). For example, it was shown in a flue-gas huff-n-puff project(2)that oil production rates stabilized, and the project proved to be cost effective with small investment requirements and low operating costs. In another case(3), the CO2 huff-n-puff process was not successful in increasing incremental oil recovery. However, there were reduced water-handling and electrical requirements during the injection, soak, and flow phases, which were beneficial to the project. There is increasing interest in CO2/flue-gas huff-n-puff injection into single wells because the process is relatively easy to apply and does not require a large initial capital outlay. The process typically begins with the injection of a slug of gas into a single well. This is followed by a shut-in or soak period to allow the gas to dissolve into the oil, swell its volume, and reduce its viscosity. The same well is then returned to production and the response is monitored. In reservoirs with poor inter-well communication, this single-well approach may be one of the best ways, and sometimes the only way, to accelerate response in underperforming wells. Since miscibility between the reservoir oil and injected gas is not a requirement of the huff-n-puff process, it is well suited for low pressure reservoirs and for gases with high minimum miscibility pressures such as flue gas. The mechanisms involved in the production of oil during gas huff-n-puff are diverse and complex. The following mechanisms have been mentioned in the literature(4–6):oil viscosity reduction;oil swelling;solution gas drive;relative permeability hysteresis due to reduced water saturation, drainage/imbibition, and wettability alternation;repressurization;gas diffusion and mass transfer; and,interfacial tension reduction in the zone near the wellbore. The purpose of this work is to investigate the potential for applying the CO2 huff-n-puff process in a medium-gravity oil reservoir in Saskatchewan.

New Dual Purpose Chemistry for Gas Hydrate and Corrosion Inhibition

Abstract An overlooked benefit of some gas hydrate inhibitors is their potential as corrosion inhibitors. In this paper, a family of molecules was evaluated as gas hydrate inhibitors by an autoclave technique. The chemicals were concurrently evaluated as corrosion inhibitors by linear polarization resistance. The results indicate that there are design criteria based on the chemistry of these systems, which can be used to optimize their performance as both gas hydrate inhibitors and corrosion inhibitors. Introduction and Background Formation of natural gas hydrates is a common problem during oil and gas production, and has been well documented(1). Gas hydrates are molecules of natural gas trapped in crystals of frozen water. They are metastable solids in which hydrogen bonded water molecules (hosts) encase the low boiling hydrocarbon molecules (guests) in a cage-like entity. The cage-like structures can totally enclose or trap a gas molecule. The mechanism of gas hydrate formation is believed to follow a two-step process. First, clusters of hydrogen bonded water molecules form around a non-polar core. This is followed by the joining of these clusters to form gas hydrates. Gas hydrate formation is usually favoured at temperatures closer to the freezing point of water. However, under sufficient pressure, gas hydrates will form at temperatures above the freezing point of water. The resulting solids can form plugs that restrict or block gas flow during oil and gas production. The most common Gas Hydrate Inhibitor (GHI) is methanol. Methanol functions as a thermodynamic inhibitor by shifting the equilibrium requirements for hydrate formation to lower temperatures and higher pressures. However, the high dosage requirements of methanol have created logistic and environmental problems. For this reason, Low Dosage Hydrate Inhibitors (LDHIs) have been developed. LDHIs have been classified as being either kinetic or anti-agglomerant. The Kinetic Inhibitors (KIs) work at low concentrations by delaying the nucleation and growth of crystals. KIs are cost effective, but fail to inhibit agglomeration of the crystals once nucleation occurs(2). KIs also have less sub-cooling potential than anti-aglomerants. For this reason, KIs are less desirable for situations with long shut-in periods. The Anti-Agglomerates (AAs) are believed to function at the gas-water interface preventing the formation of large hydrate crystals. AA mechanisms for gas hydrate inhibition are considerably different than those of kinetic inhibitors. It is believed that AAs have a dual mechanism of action. The first mode of action is believed to affect the structure of the growing hydrate. While the AAs allow hydrates to form, they limit the growth of these hydrates, thus minimizing the risk of pipeline plugging. The growth inhibition is believed to occur as a result of binding of the AA to the surface of the initially formed hydrate, thus altering the structure of the gas cage. AAs second mode of hydrate inhibition is achieved by their behaviour as dispersants. These molecules allow the previously formed hydrates to disperse in the oil phase and allow the transportation of the gas-water mixture through the pipelines(3).

Dynamic Simulation Establishes Water-Cut Limits for Well Kickoff

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88543, "Impact of Dynamic Simulation on Establishing Water-Cut Limits for Well Kickoff," by Juan Carlos Mantecon, SPE, and Iris Andersen, Scandpower Petroleum Technology; David Freeman, SPE, Woodside Energy Ltd.; and Mark Adams, SPE, Helix-RDS, prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October. Dynamic well modeling can provide understanding and a process that ensures a well is going to flow naturally during initial kickoff or predict the water-cut limits for the restart/kickoff of naturally flowing wells after a shut-in. As reservoir pressure declines and water cut increases, naturally flowing wells often require gas lift (or some other method of artificial lift) to kick off and flow continuously. Generally, these wells encounter kickoff problems at a lower water cut than their natural-flow limit because of fluid-segregation effects in the wellbore under static conditions. Therefore, determining the kickoff limit is of primary importance to determine the optimum gas lift implementation schedule and its economic effect. Dynamic modeling of the wells during kickoff can determine the associated flowing tubinghead pressure (FTHP) that will enable the well to attain steady-state flow as a function of well productivity index (PI), reservoir pressure, and water cut. Introduction A well producing oil, water, and gas will exhibit segregation of the three fluids in the tubing during shut-in. When the well is first opened after the shut-in period, the column of gas is produced from the tubing, leaving a higher-density mixture of oil, water, and new reservoir fluid. The flowing bottomhole pressure (FBHP) of the well reaches a maximum at the point when the gas column has been produced from the tubing. As shown in Fig. 1, in certain circumstances, the weight of fluid in the tubing at this point in time does not allow the well to flow, and the well is deemed to have a kickoff problem. The water cut at which the kickoff problem is experienced usually is lower than the water cut at which the well will naturally stop flowing. Four undersaturated-oil fields with eight wells producing through a subsea system to the Cossack Pioneer floating production, storage, and offloading vessel were studied. Gas lift is expected to be required sometime in the future to kick off production from wells in the Wanaea, Lambert, and Hermes fields. The Cossack field already had gas lift installed in the single producing well (Cossack 4). The Wanaea, Lambert, and Hermes wells do not use artificial lift, although the wells do have gas lift valves installed. Studies to support the installation of gas lift flowlines and sufficient additional compression to meet future artificial-lift requirements are under way. The cost for installation of a gas lift system to support the kickoff of the Wanaea, Lambert, and Hermes wells is significant, and deferring this expenditure could increase asset value. However, the inability to kick off the wells has a bigger value effect in terms of deferred production, typically 10 times greater than the capital-expense-deferment savings.

Depositional and structural controls on Triassic reservoir performance in the Heron Cluster, ETAP, Central North Sea

The Heron Cluster fields form part of the Eastern Trough Area Project, an integrated development of a total of seven fields. The main reservoir within the cluster is the Triassic Skagerrak Formation (with undeveloped Jurassic Pentland Formation in Heron and Egret). The fields are classified as HPHT reservoirs, with initial pressures and temperatures of 9300–12 900 psi and 300–350°F respectively. Development of these fields initially assumed that the Skagerrak would be well connected and likely to have an active aquifer. However, initial production from Heron in 1998 revealed a dramatic pressure decline, indicating that the reservoir was more compartmentalized than anticipated, with little or no aquifer, necessitating a revision to the reservoir model. The Skagerrak can be subdivided into an upper, more channel-dominated interval and a lower, poorer quality, more unconfined fluvial section, bounded below by the largely playa Marnock Shale and above by the lacustrine Heron Shale. Re-description of the reservoir suggested a setting dominated by terminal splay deposits, arranged into cycles bounded by a hierarchy of shales, which formed laterally persistent, effective barriers to vertical flow. Additional perforations through the Skagerrak section encountered near virgin pressures and restored production profiles to prognosis. Egret came on-stream in 1999 with a single vertical well and again showed a rapid pressure decline, in this case additionally due to fault compartmentalization. However, it was observed that the reservoir was re-charging during shut-in periods, suggesting that the faults were transmissible with sufficient pressure drawdown. With experience from Heron and Egret on vertical compartmentalization and fault transmissibility, Skua was brought on-stream in 2001 with a single horizontal well designed to intersect as much stratigraphy as possible. The Skagerrak reservoir in Skua also exhibits Egret-like recharging across faults. Overall the Skagerrak reservoirs in the Heron Cluster appear to have the following common characteristics: good lateral connectivity, but poor to zero vertical connectivity; large faults become ‘leaky’ with sufficient pressure drawdown, and there appears to be no aquifer support. The short term production behaviour of these reservoirs is not representative of their longer-term behaviour, and in particular, short-term well tests indicate a level of compartmentalization that does not materialize during production.

A borehole temperature during drilling in a fractured rock formation

Drilling in brittle crystalline rocks is often accompanied by a fluid loss through the finite number of the major fractures intercepting the borehole. These fractures affect the flow regime and temperature distributions in the borehole and rock formation. In this study, the problem of borehole temperature variation during drilling of the fractured rock is analyzed analytically by applying the approximate generalized integral-balance method. The model accounts for different flow regimes in the borehole, for different drilling velocities, for different locations of the major fractures intersecting the borehole, and for the thermal history of the borehole exploitation, which may include a finite number of circulation and shut-in periods. Normally the temperature fields in the well and surrounding rocks are calculated numerically by the finite difference and finite element methods or analytically, utilizing the Laplace-transform method. The formulae obtained by the Laplace-transform method are usually complex and require tedious numerical evaluations. Moreover, in the previous research the heat interactions of circulating fluid with the rock formation were treated assuming constant bore-face temperatures. In the present study the temperature field in the formation disturbed by the heat flow from the borehole is modeled by the heat conduction equation. The thermal interaction of the circulating fluid with the formation is approximated by utilizing the Newton law of cooling at the bore-face. The discrete sinks of fluid on the bore-face model the fluid loss in the borehole through the fractures. The heat conduction problem in the rock is solved analytically by the heat balance integral method. It can be proved theoretically that the approximate solution found by this method is accurate enough to model thermal interactions between the borehole fluid and the surrounding rocks. Due to its simplicity and accuracy, the derived solution is convenient for the geophysical practitioners and can be readily used, for instance, for predicting the equilibrium formation temperatures.

Analytical modelling of the formation temperature stabilization during the borehole shut-in period

SUMMARY The problem of formation temperature stabilization during the shut-in period is solved analytically by the approximate generalized integral-balance method. The model accounts for the thermal history of the borehole exploitation, which may include a finite number of circulation and shut-in periods, and different flow regimes during circulation periods. The latter is determined by the temperatures of the circulating fluid and different Biot numbers that depend on intensity of the heat transfer on the bore-face. Normally the temperature fields in the well and surrounding rocks are calculated numerically by the finite-difference and finite-element methods or analytically, by applying the Laplace-transform method. Formulae, analytically obtained by Laplace transform, are rather bulky and require tedious non-trivial numerical evaluations. Moreover, in previous research the heat interactions of the circulating fluid with formation were treated under the condition of constant bore-face temperatures. In the present study the temperature field in the formation disturbed by the heat flow from the borehole is modelled by the heat conduction equation and thermal interaction of the circulating fluid with formation is approximated by the Newton relationship on the bore-face. The problem for circulation and shut-in periods is solved analytically using the heat balance integral method, where the radius of thermal influence, which defines the thermally disturbed domain, is a function of time, which satisfies the algebraic equation. Within this method, the approximate solution of the heat conduction problem is sought in the form of a finite sum of functions which belong to a complete set of the linearly independent functions defined on the finite interval bounded by the radius of thermal influence and satisfy the homogeneous boundary condition on the bore-face. It can be proved theoretically that the approximate solution found by this method converges to the exact one. Numerical results illustrate quite good agreement between the approximate and exact solutions. As a result of its simplicity and accuracy, the derived solution is convenient for geophysical practitioners and can be readily used, for instance, for predicting equilibrium formation temperatures.

Repeated seismic reflection measurements in the Kakkonda geothermal field

Temporal variations in seismic reflection responses apparently caused by changes within a geothermal reservoir have been detected in the Kakkonda field, where production wells were shut in prior to annual power plant maintenance. Three seismic surveys were carried out during a 12-day period spanning the shut-in period. Receivers were deployed without replanting throughout the surveys, providing good data acquisition repeatability. We applied prestack time migration (PSTM) to each of the three seismic data sets and calculated the cross-correlation coefficients between PSTM sections. Our results indicate that the reservoir changes associated with shut-in are large enough to be seismically detectable. The region over which the seismic response changed corresponds to the zone of geothermal fluid flow paths inferred from reservoir temperatures and geochemical data. We have also compared our cross-correlation maps with the epicenters of micro-earthquakes, which are inferred to indicate the existence of fractured zones. Dense regions of micro-earthquake activity lie within the seismically identified zone of changes in reservoir properties. We demonstrate the feasibility of repeated seismic surveys in providing substantial improvements in temporal resolution during geothermal reservoir monitoring.

Mathematical Modeling of the Soaking Period in a Microbial Enhanced Oil Recovery Application

In this study, experimental conditions of the microbial enhanced oil recovery (MEOR) technique applied for Garzan oil (26° API; southeast Turkey) were utilized in a mathematical model that describes the transport of bacteria and its nutrients by convective and dispersive forces, including bacterial decay and growth. From the results of the variation of bacterial concentration with distance, it was observed that the bacterial concentration increased as the nutrients were consumed with time. Although some bacteria died during the experiments, this did not slow down the overall increase in bacterial population significantly at earlier times. However, in the later periods of the soaking process, severe bacterial decay occurred due to the lack of nutrients. The pressure behavior in the model during the shut-in period was also calculated and agreed well with the experimental results.

Propagation of Chromium(III) Acetate Solutions Through Dolomite Rock

Summary Chromium(III)-polymer gel systems are often used in permeability modification treatments for flow control. In-depth treatment of the carbonate rock matrix by these systems is of concern because rock-fluid interactions can lead to loss of chromium and may limit the penetration of a gel treatment. This paper describes a study of chromium retention in dolomite cores in the absence of polymer and demonstrates that precipitation of chromium is the principal retention mechanism. Displacement experiments were conducted in which chromium(III) acetate solutions were continuously displaced at different flow rates through Baker dolomite cores with permeabilities from 19 to 25 md. In some experiments, the cores were shut in and the resident fluid displaced and analyzed to determine chromium retention during the shut-in period. There was significant retention of chromium in the core in both continuous and shut-in experiments. In the continuous displacements, effluent concentration profiles were a function of flow rate, indicating that the retention was a rate-dependent process. In the range of concentrations studied, 0 to 1% by weight, the presence of KCl increased the retention rate. At the lowest flow rate used, effluent chromium concentration approached a steady-state value that was much smaller than the injected concentration. The retention capacity of the rock appeared to be infinite. Chromium concentrations at various residence times were compared to values predicted from a kinetic model developed for precipitation from bulk solutions. The kinetic model fit the precipitation rate data well and is consistent with the conclusion that precipitation is the principal retention mechanism. However, the induction period observed in bulk solutions was not present in the data taken in the cores. Precipitation occurred faster in the cores than in the batch experiments. The experimental results indicate that chromium is precipitated at a relatively high rate when chromium acetate solution is in contact with dolomite core material. This loss of chromium may inhibit gelation and limit the depth of penetration of a gel system in dolomite matrix rock.

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.

Estimation of static formation temperatures in geothermal wells

Stabilized formation temperatures were estimated at different depths in 40 wells from the Los Humeros geothermal field, Mexico, using the Horner and the spherical radial flow (SRF) methods. The results showed that the Horner method underestimates formation temperatures, while the SRF method gives temperatures that are closer to the true formation temperatures. This was supported by numerical simulation of a combined circulation and shut-in period in several wells, and results for well H-26 are presented. Numerical reproduction of logged temperature is more feasible if an initial temperature profile based on the SRF method is employed instead of using an initial temperature profile based on the Horner method.