Bottomhole Conditions Research Articles

Field Treatment To Stimulate an Oil Well in an Offshore Sandstone Reservoir Using a Novel, Low-Corrosive, Environmentally Friendly Fluid

Summary Acidizing sandstone formations is a real challenge for the oil and gas industry. Fines migration, sand production, and additional damages caused by precipitation are some of the common concerns related to sandstone treatments. Furthermore, the complexities of sandstone formations require a mixture of acids and loadings of several additives. The environmentally friendly chelating agent glutamic acid N,N-diacetic acid (GLDA) was used successfully to stimulate deep gas wells in carbonate reservoirs. It was tested extensively in the laboratory to stimulate sandstone cores with various mineralogies. Significant permeability improvements were reported in previous papers over a wide range of conditions. In this paper, the result of the first field application is evaluated with a fluid based on this chelating agent to acidize an offshore, sour oil well in a sandstone reservoir. The field treatment included pumping a preflush of xylene to remove oil residues and any possible asphaltene deposited in the wellbore region, followed by the main stage that contained 25 wt% GLDA, a corrosion inhibitor, and a water-wetting surfactant. The treatment fluids were displaced into the formation by pumping diesel. The treatment fluids were allowed to soak for 6 hours, then the well was put into production, and samples of flowback fluids were collected. The concentrations of key cations were determined using inductively coupled plasma, and the chelant concentration was measured using a titration method with ferric chloride solutions. Corrosion tests conducted on low-carbon-steel tubulars indicated that this chelant has low corrosion rates under bottomhole conditions. No corrosion-inhibitor intensifier was needed. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without causing sand production, or fines migration. Analysis of flowback samples confirmed the ability of the chelating-agent solution to dissolve various types of carbonates, oxides, and sulphides, while keeping the dissolved species in solution without causing unwanted precipitation. Unlike previous treatments conducted on this well, where 15 wt% hydrochloric acid (HCl) or 13.5 wt%/1.5 wt% HCl/hydrofluoric acid (HF) acids were used, the concentrations of iron and manganese in the flowback samples were negligible, confirming the low corrosion rates of well tubulars when using GLDA solutions.

PVT behavior of methane and ester-based drilling emulsions

Abstract Well construction is especially complex in deep and ultra-deep water, where large Brazilian oil and gas reserves are located, demanding the use of synthetic-based drilling fluids, which have adequate characteristics such as lubricity, shale stabilization and low toxicity. Hydrocarbon gas kick will dissolve to some extent in any drilling fluid, but this effect can generally be ignored with a water-based drilling fluid. However, an operator working with synthetic-based drilling fluid must have training in gas solubility to avoid a blowout situation. Methane is the main component of natural gas, while ester can be used in the formulation of synthetic drilling fluids. To study phase equilibrium of these gas–liquid mixtures, at high pressures and high temperatures, found in bottom-hole conditions, specific, work and time intensive experimental tests were performed. The objective of this work is to present the experimental PVT data obtained from methane and ester emulsion mixtures. The fluid was loaded into a PVT cell and tests were carried out at desired conditions. Gas enrichment procedure was devised to cover temperature, pressure and methane concentration range with a long-term, single liquid amount test. Thermodynamic properties such as bubble pressure, solubility, density and formation volume factor of these mixtures were calculated up to 103 MPa and 130 °C, similar to bottom-hole conditions. A model based on the Peng–Robinson equation of state was used to predict the bubble point of the mixture.

Acoustic Wireless Telemetry Reduces Uncertainty in Deepwater Drillstem Tests

Technology Update The drillstem test (DST) is one of the oldest methods used to test a formation’s capability to produce hydrocarbons. An early patent filed on drillstem testing in 1926 describes it as a method for “testing the productivity of formations encountered in drilling oil and other deep wells.” While frontiers such as deepwater drilling were far in the future, the industry was already seeking methods and equipment that were more efficient and economical than those in use then. Technology has continued to advance from mechanical openhole testing to modern annulus pressure controlled cased hole drillstem testing. An impressive array of annulus pressure-operated downhole test tools is available and provides operators with versatility and flexibility in drillstem testing. Downhole tool technology has advanced to extreme limits, with tools capable of handling bottomhole conditions of 35,000 psi and 500°F. Meanwhile, drilling technology has also progressed, with wells drilled to greater depths and in deeper water. Operating conditions pose new challenges to cost efficiency and annular pressure limitations. The inherent complexity of deepwater DST operations implies that a significant number of downhole test tools require some form of annular pressure manipulation. Tubing string tester valves, primary and backup circulating valves, bottomhole sampler triggers, and primary and backup firing heads for tubing-conveyed perforating are some examples. In deep water, the maximum allowable casing pressure has become the limiting factor in an increasing number of instances, and this reduces flexibility in designing the downhole test string. Advances in acoustic wireless telemetry have led to a novel and reliable alternative approach to operating downhole test tools in drillstem testing and providing real-time feedback of tool status, bottomhole pressure and temperature, and bottomhole fluid sample conditions. Wireless Telemetry Although wireless telemetry for downhole applications in the oil industry has been used since the 1940s, it did not gain much traction until the 1990s. Different wireless technologies have been studied and tested. Mud pulse telemetry found little use in drillstem testing because of low bandwidth and operational limitations. Electromagnetic telemetry saw some early use but also had limited data transmission capabilities, and the method does not work in subsurface salt layers.

Numerical modeling of injection, stress and permeability enhancement during shear stimulation at the Desert Peak Enhanced Geothermal System

Creation of an Enhanced Geothermal System relies on stimulation of fracture permeability through self-propping shear failure that creates a complex fracture network with high surface area for efficient heat transfer. In 2010, shear stimulation was carried out in well 27-15 at Desert Peak geothermal field, Nevada, by injecting cold water at pressure less than the minimum principal stress. An order-of-magnitude improvement in well injectivity was recorded. Here, we describe a numerical model that accounts for injection-induced stress changes and permeability enhancement during this stimulation. We use the coupled thermo-hydrological–mechanical simulator FEHM to (i) construct a wellbore model for non-steady bottom-hole temperature and pressure conditions during the injection, and (ii) apply these pressures and temperatures as a source term in a numerical model of the stimulation. A Mohr–Coulomb failure criterion and empirical fracture permeability is developed to describe permeability evolution of the fractured rock. The numerical model is calibrated using laboratory measurements of material properties on representative core samples and wellhead records of injection pressure and mass flow during the shear stimulation. The model captures both the absence of stimulation at low wellhead pressure (WHP ≤1.7 and ≤2.4MPa) as well as the timing and magnitude of injectivity rise at medium WHP (3.1MPa). Results indicate that thermoelastic effects near the wellbore and the associated non-local stresses further from the well combine to propagate a failure front away from the injection well. Elevated WHP promotes failure, increases the injection rate, and cools the wellbore; however, as the overpressure drops off with distance, thermal and non-local stresses play an ongoing role in promoting shear failure at increasing distance from the well.

Analysis on Drill String Vibration Signal of Stick Slip and Bit Bouncing

In drilling engineering, drill string premature damage are frequently observed, resulting in drilling cost and cycle prolonged. Researches show that, the common phenomenon of drill string vibration is the main cause of premature damage, thus more and more attention is paid to research on drill string vibration. Real time monitor and analysis on drill string vibration has important implications for vibration control, complex prevention, downhole condition prediction and drilling parameter optimization. Cases of vibration signal of stick slip and bit bouncing are collected and analyzed with Fourier transform, and frequency spectrum characteristic of vibration signal is obtained. The results show that, the vibration signal can reflect bottom hole condition of drill string, thus to predict premature damage of drill string and decrease drilling cost. Key words: Drill string vibration; Stick slip; Bit bouncing; Signal characteristic

Real-Time Prediction and Optimization of Drilling Performance Based on a New Mechanical Specific Energy Model

The theory of mechanical specific energy has been of great value in real-time evaluating drilling performance. Given the mechanical specific energy (MSE) of bit could not be precisely calculated at present, this work presents a new mechanical specific energy model based on the evaluation of virtues and defects of available MSE models. Meanwhile, ROP can be predicted by further deducing the model. According to the relations between MSE, CCS, drilling parameters and ROP, a real-time drilling performance predicting and optimizing method is proposed by analyzing bottom-hole conditions of drilling and determining the reasonable drilling parameters. The new mechanical specific energy model and the real-time optimizing method are tested through field logging data. The results show that the calculation precision of the new mechanical specific energy model is the highest, and the calculation error is the minimum both in vertical section and horizontal section, which can make MSE applied more widely including horizontal wells and can be quantitatively applied. The prediction accuracy of ROP is very high, which can fully meet the needs of engineering of the field. The real-time drilling performance predicting and optimizing method with highly diagnostic accuracy, effective optimizing and simple operation are demonstrated by field examples, and it is worthy to be applied and promoted.

English

In recent times, drillers all over the world are encountering highly fractured or matured reservoirs. Conventional drilling techniques are failing to drill efficiently and economically, causing problems of formation damage, lost circulation etc. With increasing energy demands, the industry requires to develop new techniques that can exploit these formations effectively and minimize the problems associated with conventional drilling. In-depth investigations over the years established that underbalanced drilling with foam fluid could be one of the best possible solutions for efficient production from these reservoirs. They have high viscosity and high cutting carrying capability with unusually low density. However, little is known about their rheology, stability and hydrodynamics in dynamic bottomhole conditions, rendering their use difficult in drilling operations. The present work focused on the study of various rheological and stabilization aspects of foam-based drilling fluids for different surfactant and polymer combinations. An optimized combination was predicted for surfactants and polymers which helps in the modeling of different foam hydraulics parameters of the drilling fluids.

Extreme High-Pressure and/or High-Temperature Wireline-Data Acquisition: Planning for Success

Summary Data acquisition in extreme environments of high pressure and/or high temperature (HPHT) with pressures up to 30,000 psi and temperatures up to 500°F requires not only specialist technology capable of surviving these conditions but also many months of preparation and planning to ensure a successful operation. The aim of this publication is to provide an overview of what is involved in the planning, preparation, and execution of an extreme HPHT wireline data acquisition—from the customer setting the information objectives through to data delivery. This includes developing an agreed quality plan between the data provider and the customer covering testing and deployment of the latest extreme HPHT logging equipment. One must consider all aspects to minimize risks including detailed tailoring of the logging programs to manage time in hole, to ensure accurate depth control, and, by using a deployment risk-management process, to ensure that what goes in the hole comes out again. The implementation of these procedures is illustrated with a case history of a series of HPHT exploration wells drilled in the Central Graben of the North Sea (the "HPHT Heartland" of the North Sea). Bottomhole conditions were predicted to approach 400°F and 15,000 psi. These extreme conditions negated the use of conventional wireline tools, and so, from initial early planning discussions between client and service provider, new detailed programs were designed and implemented as a specific "Quality Plan" to use the advanced HPHT wireline-logging tools.

Dynamic safety risk analysis of offshore drilling

The exploration and production of oil and gas involve the drilling of wells using either one or a combination of three drilling techniques based on drilling fluid density: conventional overbalanced drilling, managed pressure drilling and underbalanced drilling. The conventional overbalanced drilling involves drilling of wells with mud which exerts higher hydrostatic bottom-hole pressure than the formation pore pressure. Unlike the conventional overbalanced drilling, underbalanced drilling involves designing the hydrostatic pressure of the drilling fluid to be lower than the pore pressure of the formation being drilled. During circulation, the equivalent circulating density is used to determine the bottom-hole pressure conditions. Due to lower hydrostatic pressure, underbalanced drilling portends higher safety risk than its alternatives of conventional overbalanced drilling and managed pressure drilling. The safety risk includes frequent kicks from the well and subsequent blowout with potential threat to human, equipments and the environment.Safety assessment and efficient control of well is critical to ensure a safe drilling operation. Traditionally, safety assessment is done using static failure probabilities of drilling components which failed to represent a specific case. However, in this present study, a dynamic safety assessment approach for is presented. This approach is based on Bow-tie analysis and real time barriers failure probability assessment of offshore drilling operations involving subsurface Blowout Preventer. The Bow-tie model is used to represent the potential accident scenarios, their causes and the associated consequences. Real time predictive models for the failure probabilities of key barriers are developed and used in conducting dynamic risk assessment of the drilling operations. Using real time observed data, potential accident probabilities and associated risks are updated and used for safety assessment. This methodology can be integrated into a real time risk monitoring device for field application during drilling operations.

Technology Focus: Multilateral/Extended Reach (May 2014)

Technology Focus The oil industry has always been innovative, even under adverse and challenging conditions imposed by the nature of upstream projects. In the past, drilling and completion activities have faced the complexity of the wells and tougher operational and environmental regulations with ingenuity and efficiency. Some prospects considered not feasible 5 years ago are delivering an attractive rate of return to shareholders after the implementation of new techniques. On a day-by- day basis, deepwater, extended-reach, slimhole, and environmentally sensitive drilling projects are reaching the limit of industry capability and pushing for faster evolution in terms of technology, equipment, and procedures. It is not rare anymore to deal with prospects that require pressure ratings of 20,000 psi, temperatures greater than 350°F, and measured depths to 40,000 ft. These challenging project characteristics are leading to a review of conventional techniques and the use of innovative technology for wellbore positioning in a thin oil column, long horizontal drilling and completion legs, extremely low fracture margin in deepwater wells, and downhole tool telemetry. In the case of extended-reach wells (ERWs), the extension of horizontal legs aligned with low gradient fracture in deepwater projects requires an appropriate pressure-management system to mitigate the effect of friction losses at bottomhole conditions. The horizontal legs of multilaterals and ERWs are reaching lengths of 11,000 to 12,000 ft, with corresponding high friction losses that preclude the setting of casing shoes at planned depth in conventional drilling methods because of the equivalent circulating density (ECD). This challenge becomes even more critical when dealing with deepwater environments. Techniques such as the Reelwell drilling method (RDM) and managed-pressure drilling (MPD) have advanced considerably in recent years and are now feasible alternatives to mitigate the ECD and, consequently, are helping the execution of ERWs onshore and offshore. For example, RDM has a unique flow architecture that uses a conventional drillstring combined with an inner string to form a dual-conduit drillstring. This arrangement allows the return fluid containing cuttings to be transported back through the inside of the drillstring, thus eliminating the ECD. RDM also has the advantage of increasing the drilling envelope for ERWs because of torque and drag reduction and optional hydraulic weight on bit caused by a piston-type arrangement at the drillstring. It is difficult to comment about all the new available technologies in this summary, but the following papers address other advancements that are making possible the continuity of drilling and completion activities in a responsible, safe, and feasible way. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 166143 Multilateral Wells in the Urucu Field of Western Brazil: Reducing Environmental Impact in the Amazon by Sandro Mendes, Petrobras, et al. OTC 23985 Combining Contemporary and Tested Technologies To Achieve Successful Deepwater Extended-Reach Completions by Ray Brister, Chevron, et al. SPE/IADC 168049 New Rotary- Shouldered Connection Expands the Capability of World-Record ERD Operation by S.R. Sanford, ExxonMobil, et al.

A Transient Flow Model of Non-Newtonian Heavy Oil Under Different Bottom-hole Producing Pressure Conditions

Great emphasis has been placed on non-Newtonian heavy oil. Most researches consider the heavy oil as a Bingham fluid. But the viscosity of heavy oil that changes with temperature and dynamic radius in the development process is not taken into account. In order to study the flow feature of non-Newtonian heavy oil, the dynamic radius and viscosity are presented first. And then a mathematical model for transient flow of non-Newtonian heavy oil with dynamic radius and variable viscosity under different bottom-hole producing pressure conditions is established. The non-Newtonian transient pressure distribution of heavy oil under different bottom-hole producing pressure conditions is obtained by difference method on time and space and programming with MATLAB. The results show that under the same pressure difference, the dynamic radius is closer to the well as the threshold pressure gradient increasing. The greater the threshold pressure gradient is, the greater the pressure drop near the well is. The research combines the dynamic radius and the changes of viscosity avoiding the shortcoming of the existing non-Newtonian heavy oil flow mathematical model.

A Simple and Reliable Approach for the Estimation of the Joule-Thomson Coefficient of Reservoir Gas at Bottomhole Conditions

Summary With the advent of distributed temperature sensing (DTS), accurate and continuous monitoring of the wellbore-temperature profile is possible, which helps identify fluid flow from each reservoir layer. The reliable prediction of fluid flow during large drawdown requires an accurate value of the Joule-Thomson coefficient (JTC), which is a measure of the change in temperature (T) of a fluid for a given change in pressure (P) at constant enthalpy. The JTC also serves as an input for the interpretation of temperature-log data, which can be used to identify water- or gas-entry locations. Furthermore, an accurate JTC value is important when modeling the thermal response of the reservoir. The equation-of-state (EOS) method can be used to predict the JTC of reservoir gas. However, this might not be an easy task because of the complexity involved. In contrast, a simple and reliable method to evaluate the JTC for reservoir gas is presented. Conditions under which this method is applicable are discussed in detail by referring to a typical phase diagram. In addition, a discretized approach to calculate the temperature change during a throttling process with the JTC is also presented. The methodology has been validated at three levels with experimental data available in the literature—comparison of experimental vs. predicted JTC values of mixtures, comparison of experimentally observed vs. predicted temperature drop for a given pressure drop with laboratory-scale data, and comparison of experimentally observed vs. predicted temperature drop for a given drawdown with actual reservoir data. A good match with experimental data was obtained within all three areas, demonstrating the reliability of the methodology.

Downhole Mixing Technique Facilitates Pinpoint Fracturing in Eagle Ford Shale

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153312, ’Downhole Mixing Fracturing Method Using Coiled Tubing Efficiently: Executed in the Eagle Ford Shale,’ by S. Lindsay, SPE, C. Ables, SPE, and D. Flores, Halliburton, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed. The increased demand for natural gas from shale plays in the United States has forced the industry to be more efficient and develop innovative methods for fracture-stimulation optimization. Pinpoint-fracturing methods represent a divergence from the conventional methods, with minimal optimization needed to help maximize reservoir volume. Multiple-interval completions can be performed efficiently so that all intervals receive the designed proppant volumes, one interval at a time. To accomplish this efficiency, coiled tubing (CT) is used to hydrajet perforate intervals for individual fracturing treatments at predesigned depths. The latest pinpoint-fracturing technique provides maximum engineering flexibility in the execution of these treatments by allowing downhole control of the proppant schedule; this can be used to optimize the stimulated reservoir volume (SRV) on the fly, in real time, and with downhole control. The process also incorporates large-outer-diameter (OD) CT. A recent 25-interval completion in the Eagle Ford shale demonstrated the process. Introduction The downhole mixing process (DMP) allows multiple-interval fracturing treatments in horizontal laterals in a single trip. The DMP enables the fracturing treatment to be manipulated in real time. This allows the altering of bottomhole conditions to increase net pressure, resulting in increased complexity and more SRV compared with conventional casing fracturing treatments. Using this method, multiple treatments can be performed in a time-effective manner with less hydraulic horsepower (HHP) on location. This is a result of the higher rate per interval that is pumped into the formation. On a typical 100-bbl/min treatment with four perforation intervals, each interval receives only at a 25-bbl/min fracturing rate. This, of course, is assuming that all the intervals are of a homogeneous rock type, have the same fracture-initiation and -extension pressures, and are all receiving fluid. With the DMP, each interval is fractured individually, helping ensure that all fluid enters the desired area of the formation at the desired pumping rate. This results in a reduction in required HHP; for example, only 25 bbl/min must be pumped to achieve the desired 25-bbl/min fracturing rate in that interval. An example of this process is illustrated in Fig. 1.

Well-Performance Relationships in Heavy-Foamy-Oil Reservoirs

Summary Inflow performance in some heavy-oil reservoirs is not well understood because the fluid properties differ from conventional behavior. In this work, we develop an expression for inflow performance as a function of properties of foamy oils (e.g., density, viscosity, solution gas/oil ratio, and formation volume factor). We define two parameters, the endpoint entrained-gas fraction and the apparent bubblepoint, adapted from previous studies, to account for the extent of entrained-gas fraction in the liquid. The fluid properties are modified to account for the entrained gas and then incorporated in the equations describing flow from a reservoir at pseudosteady state. The results of our study show that the entrained gas and the apparent bubblepoint impact the fluid properties and, therefore, the inflow performance at the bottomhole conditions. In the presence of entrained gas, the density of the fluid decreases and the formation volume factor increases. Both these properties show an inflection below the bubblepoint pressure, and the solution gas/oil ratio shows a constant value until the apparent bubblepoint is reached. The inflow-performance curve, therefore, displays an inflection as opposed to the monotonically changing curve normally observed with conventional oils. The outflow-performance curve is lowered when the effect of entrained gas is included, caused by lower density; hence, the nodal systems analysis predicts a greater production rate for a foamy-oil reservoir compared with a conventional reservoir.

A Study on the Mechanism of Bottom Hole Hydraulic Pulse Increasing Drilling Rate

Practically, the distribution and variation of the bottom-hole hydraulic energy has significant influence on drilling rate, and it’s helpful to induce bottom-hole hydraulic pulse to improve the rock breaking and drilling efficiency. The analysis of bottom-hole rock stress condition and cuttings start-up mechanism indicates that, bottom-hole hydraulic pulsation can decrease the bottom hole pressure, reduce the fracture strength of rock, and strengthen bottom-hole purification, thus improve the efficiency of rock breaking and drilling. The higher the pulsation value is, the more effective of the acceleration of the drilling rate, while well depth increases, the acceleration effect diminishes gradually. Simulation of jet flow field drilled by 3-nozzle 3-cone bit, combined with field application, verify the mechanism that bottom-hole hydraulic pulsation could improve ROP. The result of the study provides a basis for the development of practical technology.

Advanced Drilling in HP/HT: Total's Experience on Elgin/Franklin (UK North Sea)

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Drilling high-pressure/high-temperature (HP/HT) exploration wells remains a challenge, despite years of experience acquired by the drilling/completion industry. Development wells have further expanded the envelope of performance of the technologies and procedures required to deliver production from HP/HT fields safely and economically. Now comes the time of drilling and completing infill wells, which paradoxically appear to be more difficult as depletion increases and the mud-weight window (MWW) diminishes. To overcome this problem, intense engineering work has been carried out to better understand the effect of the depletion on compaction and fracturing gradient, to design and qualify new drilling-mud systems combined with stress-caging techniques, and to prepare contingent solutions with the deployment of expandable- and drilling-liner technologies. Three infill wells have been drilled, completed, and put on production by Total in the Elgin/Franklin fields on the UK Continental Shelf. This success was achieved through severely depleted reservoirs—with depletion greater than 800 bar—and has enabled phased HP/HT developments and deep exploration beneath depleted horizons. Overview of the Elgin/Franklin Extreme-HP/HT Fields The Elgin/Franklin fields present an extreme combination of pressure and temperature (1,100-bar virgin pressure and 200°C, respectively) and remain the largest HP/HT gas/ condensate fields developed in the British sector of the North Sea. The fields are approximately 200 km northeast of Aberdeen in the Central Graben area. Following discovery and appraisal from 1985 to 1994, development started in 1996 with two unmanned wellhead platforms tied back to a central production facility. Eleven wells were drilled and put on stream, with deviations up to 50°, in an average drilling duration of 120 days. These wells were drilled before a predefined limit of depletion level had been reached, a level at which the MWW closes—calculated for Elgin/Franklin as 100 bar. First oil production occurred in 2001. Later, two satellite structures, Glenelg and West Franklin, were drilled and put on production through the existing installations in 2006 and 2007, respectively, (Fig. 1). The reservoirs consist of Jurassic sandstones buried at a depth exceeding 5300 m. The primary reservoir is the Fulmar, also called Franklin, sands. Reservoir fluids are gas/ condensate with a bottomhole pressure of 1100 bar and temperature of 190°C. The Fulmar reservoir is underlain by the Pentland reservoir with bottomhole conditions of 1150 bar and 200°C (Fig. 2). Despite the depth, the main reservoir shows significant porosity and permeability, allowing strong productivity. Up to 30% porosity and 1-darcy permeability are found in some Fulmar layers Individual wells in the field can produce up to 3.5×106 m3/d of gas with associated condensate. Surface production conditions are 860-bar wellhead shut-in pressure with an associated temperature of 180°C. The produced effluent contains 3 to 4% CO2 and 30 to 40 ppm H2S. Initially, field gas production reached 14.6×106 m3/d, with 24 000 m3/d of condensate. This combination explains the strong need for technology and in-depth engineering for these wells.

Using downhole temperature measurement to assist reservoir characterization and optimization

Without initial seismic or detailed geological information, reservoir characterization is difficult. Downhole temperature distribution in horizontal wells is an important source that helps to characterize the reservoir and understand the bottom-hole flow conditions. The temperature measurements are obtained from permanent monitoring systems such as downhole temperature gauges and fiber optic sensors. Additionally, production history and bottomhole pressures are usually readily available and are routinely used for history matching to improve the initial geological models. By combining the downhole temperature distribution and the production history, more reliable information can be extracted about the reservoir permeability distribution and bottomhole flow conditions in order to optimize the wellbore performance, particularly in horizontal wells. In this paper, a thermal model and a transient, 3D, multiphase flow reservoir model are used to calculate the wellbore temperature distribution in horizontal wells. By comparing the simulated temperature and the observed data, large-scale permeability trends in the reservoir are derived. These permeability trends are then incorporated as ‘secondary’ information in the geologic model building and history matching. The final outcome is a geologic model that has the constraints of both temperature and production history information. A synthetic case is presented to illustrate the procedure. The results show when using production history matching only without distributed temperature data along the wellbore, the water entry location in horizontal wells cannot be detected satisfactorily. By combining production history matching with downhole temperature distribution data in a wellbore, an improved geological model is developed that can match production history and locate water entries correctly. Based on the downhole flow conditions and the updated geological model, the well performance can be optimized by controlling the inflow rate distribution in a horizontal well.

Drilling Through Gas-Hydrate Sediments: Managing Wellbore-Stability Risks

Summary As hydrocarbon exploration and development moves into deeper water and onshore Arctic environments, it becomes increasingly important to quantify the drilling hazards posed by gas hydrates. To address these concerns, a 1D semianalytical model for heat and fluid transport in the reservoir was coupled with a numerical model for temperature distribution along the wellbore. This combination allowed the estimation of the dimensions of the hydrate-bearing layer where the initial pressure and temperature can dynamically change while drilling. These dimensions were then used to build a numerical reservoir model for the simulation of the dissociation of gas hydrate in the layer. The bottomhole pressure (BHP) and formation properties used in this workflow were based on a real-field case. The results provide an understanding of the effects of drilling through hydrate-bearing sediments (HBS) and of the impact of drilling-fluid temperature and BHP on changes in temperature and pore pressure within the surrounding sediments. It was found that the amount of gas hydrate that can dissociate will depend significantly on both initial formation characteristics and bottomhole conditions) namely, mud temperature and pressure). The procedure outlined in the paper can provide quantitative results of the impact of hydrate dissociation on wellbore stability, which can help in better design of drilling muds for ultradeepwater operations.

Introducing Generalized Boundary-Dominated Flow Equations Applicable for Various Oil Reservoir Models

Boundary-dominated flow equations are commonly applied for estimation of parameters such as hydrocarbon in place and well drainage area. The well may be operated in constant rate, constant pressure, and variable flowing bottomhole conditions. For each case, production data must be analyzed in a different way. In this article, three generalized equations are introduced for the cases of constant well rate, constant well pressure, and variable flowing bottomhole conditions that are applicable for any reservoir model. As a verification of these equations, boundary-dominated flow equations for five reservoir models are introduced and compared with generalized equations. The equations introduced for each reservoir model are validated with the use of analytical solutions.

Prediction of Gas Wells Performance Using Wellhead and Production Data

The monitoring of gas wells is quite challenging principally because the gas supply contract is usually signed before the gas production commences. Consequently, production potential above the daily contractual quantity is normally maintained to ensure that gas demand is met even in the case of unexpected closure of any of the gas wells. Therefore, meeting the gas demand sometimes does not allow regular data acquisition as required. In the approach presented in this study, the well and production data were used to estimate the productivity parameters at the bottom hole condition of a gas well using correlation. The correlation predicts the flowing bottom hole pressure for every set of production data. The estimated flowing bottom hole pressures compare favorably with the measured data. Using the predicted flowing bottom hole pressure, the gas well productivity parameters are determined. The resulting inflow performance relationship of the well demonstrates the reliability of this method in real time well performance evaluation. The application of this method is presented using a gas well that initially had poor performance but which improved significantly after an acid stimulation.