Bottom-hole Temperature Research Articles

Well-Testing Operations in High-Temperature Environments - Experiences and Best Practices

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148575, ’Challenging Well-Testing Operations in High-Temperature Environments - Worldwide Experiences and Best Practices Learned,’ by Alejandro Salguero, SPE, Edgar Almanza, and Josmar Haddad, SPE, Halliburton, prepared for the 2011 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Muscat, Oman, 24-26 October. The paper has not been peer reviewed. High-temperature (HT) wells are classified as those with bottomhole temperatures in excess of 300°F. New technologies and advances in the industry (e.g., gauges, downhole equipment, and samplers) have been applied to improve decision-making capabilities and to increase well-testing-evaluation success, even in extreme and challenging environments. These enhancements enable improved economics and operational efficiency along with better safety conditions for the involved personnel and lower environmental risk during testing operations. Introduction Well testing is a reliable, dynamic method of retrieving and collecting a variety of information from the reservoir, including permeability, formation damage, bottomhole pressure and temperature, fluid samples, and production quantification. The methods and equipment used to collect these data have evolved as exploration has moved into more-demanding and -challenging environments. In recent years, high-pressure/high-temperature (HP/HT) wells have become more common, and they required new techniques that support the environmental challenges. Proper planning and personnel and qualified equipment are key to achieve successful well-test results, especially considering that well and reservoir conditions can change easily from one region to another, adding challenges to the evaluation operation. HT prospects are defined as wells having bottomhole temperatures in excess of 300°F, and extreme HT wells are prospects having bottomhole temperatures of 350 to 400°F. The chart in Fig. 1 depicts designations for each pressure and temperature definition. Most HT cases have required the use of a deep-well simulator to test and qualify/certify equipment for the expected well-test conditions. The complete paper details three cases of testing wells with temperatures ranging from 340 to 430°F. These cases were carried out in different geographical locations. These wells were chosen because different bottomhole configurations of full-scale downhole assemblies were used. It is important to mention that special tools and equipment are available to perform operations under extreme conditions (e.g., 450°F and 20,000 psi). Currently, electronic memory gauges used in drillstem-test (DST) equipment are designed and tested to work in conditions of 400°F and 30,000 psia. Real-time gauges are available that have been tested to 350°F. However, when more-challenging conditions are encountered, mechanical pressure and temperature gauges must be used.

Chemical Modification of Biopolymers To Design Cement Slurries With Temperature-Activated Viscosification—A Laboratory Study

Summary Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, which, in some cases, might exceed formation breakdown pressures causing unintended fractures.This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing. This paper describes a chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose (HEC) and xanthan—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries containing modified HEC are heated, the slurries develop viscosity upon heating, as reflected by changes to slurry rheology with temperature. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.

Designing Multistage Frac Packs in the Lower Tertiary Formation–Cascade and Chinook Project

Summary The Cascade and Chinook Project is located in the Walker Ridge area in the Gulf of Mexico (GOM), 250 miles south of New Orleans in depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth subsea (TVDss), with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in Moraes et al. (2010). Multiple limitations were considered during the initial design phase of the frac-pack program. The fracs were designed taking into account the use of a single-trip multizone (STMZ) sand-control system. Some of these design challenges are briefly discussed by Cunha et al. (2009). Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operational standpoint because of a continuous, multistage frac operation. Some of the operational limitations included service-tool erosion limitations because of maximum pump rates and proppant volumes, overall frac-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool-spacing limitations, and still maximize contact with net pay. This paper addresses the approach taken to develop a fracture-stimulation program for the Lower Tertiary formation in the Cascade and Chinook Project. Some of the major questions addressed during this process include the following: How many fracture treatments are needed? What is the optimum fracture geometry? What is the desired conductivity? How to effectively position the perforation intervals? What is the desired pump rate, and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers, and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations. Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (caused by depth and in-situ stresses) where fracturing is required for both stimulation and potential formation-collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.

Toluene Depletion in Produced Oil Contributes to Souring Control in a Field Subjected to Nitrate Injection

Souring in the Medicine Hat Glauconitic C field, which has a low bottom-hole temperature (30 °C), results from the presence of 0.8 mM sulfate in the injection water. Inclusion of 2 mM nitrate to decrease souring results in zones of nitrate-reduction, sulfate-reduction, and methanogenesis along the injection water flow path. Microbial community analysis by pyrosequencing indicated dominant community members in each of these zones. Nitrate breakthrough was observed in 2-PW, a major water- and sulfide-producing well, after 4 years of injection. Sulfide concentrations at four other production wells (PWs) also reached zero, causing the average sulfide concentration in 14 PWs to decrease significantly. Interestingly, oil produced by 2-PW was depleted of toluene, the preferred electron donor for nitrate reduction. 2-PW and other PWs with zero sulfide produced 95% water and 5% oil. At 2 mM nitrate and 5 mM toluene, respectively, this represents an excess of electron acceptor over electron donor. Hence, continuous nitrate injection can change the composition of produced oil and nitrate breakthrough is expected first in PWs with a low oil to water ratio, because oil from these wells is treated on average with more nitrate than is oil from PWs with a high oil to water ratio.

Liquefied CO2 Injection Modelling

A dynamic simulation model of an injection riser/pipeline/well for injection of shipped liquefied CO2 was set up using the multiphase flow simulator OLGA. Furthermore, the topside offloading process was modelled using HYSYS. The models were applied for case studies using parameters from the existing Sn∅hvit and Sleipner CO2 injection wells and reservoirs.The study quantified effects related to flow capacity (pump/compressor requirements and line sizing of the riser, pipeline and well), freezing, hydrate formation, phase change and heat transfer in the offloading and injection system.With an available injection pump discharge pressure of about 120bar, the injection capacities were predicted to about 275kg/s on Sn∅hvit and 400kg/s on Sleipner when assuming 7” ID tubing size in the well and 700 m flowline length.In the base case scenario with a 700 m buried pipeline and injection temperature of -53°C (this storage temperature on the ship, at a pressure of 7-8bar had been selected for optimum transport capacity) there is a high risk of unwanted hydrate formation and freezing in the formation and on the outer surface of the riser and pipeline. The bottomhole temperatures were predicted as low as -38 and -46°C on Sn∅hvit and Sleipner respectively when injecting at pump design rate, far beneath expected hydrate and freezing temperature of 10-12°C and -1.9°C (in salt water) respectively. Thus heating, either by topside heat exchangers and/or by utilizing the warmer sea water (5°C) via a longer injection pipeline is required to avoid problems. An alternative storage condition at -20°C and 20bar was proposed and simulated to reduce energy requirements due to heating and pressurization at the ship. The heating power was reduced by 18 MW while topside pumping power was reduced by 0.5 MW in this case.

Development of Water-Based Drilling Fluids Customized for Shale Reservoirs

Summary Drilling activity has increased dramatically in unconventional shale gas reservoirs. The drilling fluid of choice in these shale plays is often nonaqueous-based fluid (NAF). While NAFs can provide advantages such as shale stabilization, lubricity, and contamination tolerance, environmental consequences and associated costs are an issue. These disadvantages cause operators to seek water-based muds (WBMs) for drilling many of these gas reservoirs. Despite some operational similarities, a wide variety of unique downhole conditions can be found in the shale plays. Shale mineralogy and bottomhole temperature (BHT) represent just two highly variable critical factors in unconventional gas reservoirs. Therefore, a single water-based solution for addressing shale plays globally is not a realistic option. Instead, a customized approach that delivers WBMs formulated specifically for a given shale play has been pursued. Customization relies on detailed analysis of the well parameters of a given shale play. This analysis includes not only the shale morphology and lithology but also well drilling program plans, environmental factors, and other reservoir-specific considerations. Applying appropriate drilling-fluid chemistries on the basis of this detailed analysis has led to the successful field deployment of a number of new shale fluids. Details of the process used for customizing a WBM for a shale play, as well as specific examples of new fluids developed for the Barnett, Fayetteville, and Haynesville shales, are presented in this paper. Full laboratory development and testing are described. Additionally, field-trial results are presented that show that specially designed WBMs can provide performance comparable to that of NAFs, but with enhanced environmental and economic benefits. Application of the customization process to develop WBMs for other shale plays around the globe is also discussed.

Determination of geothermal gradient and heat flow distribution in Delta State, Nigeria

Geothermal and heat flow distribution study was carried out at eighteen locations in Delta State, Nigeria using field data obtained from temperature logging and thermal conductivity measurements. The study shows that the geothermal gradients for the area ranges from a minimum of 25.47°C/km to a maximum of 31.16°C/km and a mean geothermal gradient of 28.64°C/km. This result indicates that the geothermal gradient falls within the range interval typical of the gradients commonly encountered in tectonically inactive areas. The study also shows that the heat flow ranges from 38.93 to 89.59 mWm-2 with a mean heat flow of 62.70 mWm-2. The study reveals that the heat flow and geothermal gradient of the study area decreases southward toward the ocean. This implies that fluid migration path is to the south of the study area. Key words: Heat flow, geothermal gradient, temperature, thermal conductivity, bottom-hole temperature.

Thermal properties of the AND-2A borehole in the southern Victoria Land Basin, McMurdo Sound, Antarctica

The ANDRILL (Antarctic Geological Drilling Program) Southern McMurdo Sound Project (SMS) drilled a 1138-m-deep borehole (AND-2A) within Neogene strata in the southern Victoria Land Basin of the West Antarctic Rift in the Ross Sea, Antarctica, during the 2007–2008 austral spring. An extensive downhole logging program was carried out in the SMS borehole that included temperature and spectral gamma ray logs. These logging data were combined with lab measurements of the thermal conductivity of core samples to deduce several thermal parameters of the borehole country rock. The results indicate a bottom-hole temperature of 57.8 °C and an average temperature gradient of 51.9 K/km. Thermal conductivities on core samples range from 1.22 to 2.95 W/mK and average 1.57 W/mK. Thermal conductivities coupled with the average temperature gradient yield an average heat flow of 81.5 mW/m2, a minor amount (1.1 mW/m2) of which is generated by radiogenic heat production. Temperature, gradient, and heat flow are considered as possible minimum values. The average heat flow determined for the SMS borehole therefore provides important confirmation that heat flows are locally above average values for continental crust in the southern Victoria Land Basin of the West Antarctic Rift system. This new heat flow constraint is consistent with extension and volcanism within the Terror Rift, which was active in Neogene time.

Failure assessment of the hard chrome coated rotors in the downhole drilling motors

In this investigation, the premature failure of the hard chrome coated rotors of the downhole drilling motors is studied. The main part in these motors is the power section, composed of a metallic rotor and an elastomeric stator. The rotor is manufactured from 17-4 PH stainless steel and rotates within a stator and displaces the drilling fluid forward. Drilling fluid characteristics change upon circulation and influxes, and cause erosion and corrosion of the rotor. Different types of damages such as scratches, deep and shallow cuttings, spalling, pits, micro and macrocracks are observed on chrome plated rotor surface. Effects of working parameters such as bottom hole temperature and solid content on life time of rotors are investigated. Chemical analysis and microscopic examinations of rotor and its coating are also carried out to identify the causes of failure. It was found that, drilling fluids are corrosive in nature and their solid content are too high for chrome coated rotors.

Analytical and numerical modeling reveals the mechanism of rock failure in gas UBD

Underbalanced drilling (UBD) has been proven to be an effective means of increasing drilling performance and minimizing formation damage. While UBD with gases (air, nitrogen, natural gas, etc.) gives the highest rate of penetration (ROP), addition of liquid phase significantly reduces ROP. The objective of this study was to understand the mechanism of rock failure that controls the ROP and use the gained knowledge to optimize gas UBD design. An analytical model was developed in this study to calculate the near-wellbore rock stresses induced by the bottom hole pressure and temperature. A numerical model with finite element method was used to verify the results from the analytical model. Both of the analytical model and the numerical model reveal that the rock stress in the bottom hole rock can change from compressive stress in over-balanced conditions to tensile stress in underbalanced conditions, depending on the bottom hole pressure. A new finding from this study is that the temperature-induced stresses in the bottom hole rock can contribute significantly to the stress unbalance and cause rock failure. This paper provides drilling engineers insight and understanding of rock failure mechanics, which are useful for designing bottom hole pressure and gas injection rate to improve UBD performance.

Thermohydrodynamic investigations of vertical oil wells

A method for determining filtration and thermophysical parameters of beds is proposed. The curves of variations in the bottom-hole temperature taken after activation of a vertical well are used as the source data.

Designing Multistage Frac Packs in a Lower Tertiary Formation - Cascade and Chinook Fields

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140498, ’Challenges of Designing Multistage Frac Packs in the Lower Tertiary Formation - Cascade and Chinook Fields,’ by Ziad Haddad, SPE, FOI Technologies; Mike Smith, SPE, NSI Technologies; and Flavio Dias De Moraes, SPE, Petrobras, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed. Offshore frac-pack operational limitations include service-tool erosion, overall fracture-treatment-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. Geological complexities were another major challenge in completing this very thick interval. Perforation intervals had to be placed in a manner to avoid a fault (and thus a potential early screenout), to avoid a water contact, and to comply with tool-spacing limitations, while maximizing contact with net pay. A specific approach was developed to design the fracture-stimulations for a Lower Tertiary formation in the Cascade and Chinook fields. Introduction The Cascade and Chinook fields are 250 miles south of New Orleans in the Gulf of Mexico (GOM) in ultradeep-water depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth (TVD) with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with no effective vertical permeability. It was recognized early on that dealing with the Lower Tertiary formation required a change in focus from a soft-rock frac-pack completion to a hard-rock hydraulic-fracturing completion, similar to those used in the Wilcox formation in south Texas. The secondary objective was to design a sand-control completion to retain the proppant pack and eliminate proppant flowback in screenless hard-rock fracturing completions. To outline a basis of design for future Cascade and Chinook hydraulic-fracturing treatments, the initial planning phase was to develop a complete and comprehensive set of fracture-treatment-design data to be used in developing the preliminary treatment designs and evaluating the material-selection options, and to identify key questions for future wellsite data collection and execution. The full-length paper details this outline. Design Challenges The first well completed in the Cascade field was completed with three propped-fracture treatments in the upper and lower Wilcox zones. The challenge was to complete this very thick interval while avoiding fracturing the oil/water contact and avoiding placing perforations too near the fault at 25,832 ft measured depth (MD).

Effect of the load condition on frictional heat generation and temperature increase within a tri-cone bit during high-temperature formation drilling

To investigate the effect of the load condition on frictional heat and temperature within a tri-cone bit, a series of experiments were performed to simulate the mechanical conditions during drilling. The bearing characteristic number, which indicates load conditions such as rotation speed, weight on the bit, and flow resistance, was used to interpret the results. The Stribeck curve of the bearing shows the bearing was in a state of mixed (boundary + elasto-hydrodynamic) lubrication, not in a smooth hydrodynamic lubrication. When drilling high-temperature formations, the bottomhole temperature is higher than that in the experiment, and mixed lubrication progresses to boundary lubrication. The temperature within the bit increases readily, damaging the O-ring seal in the journal bearing.

The geothermal project Den Haag: 3D numerical models for temperature prediction and reservoir simulation

The proposed Den Haag Zuidwest district heating system of the city of The Hague consists of a deep doublet in a Jurassic sandstone layer that is designed for a production temperature of 75 °C and a reinjection temperature of 40 °C at a flow rate of 150 m 3 h −1. The prediction of reservoir temperature and production behavior is crucial for success of the proposed geothermal doublet. This work presents the results of a study of the important geothermal and geohydrological issues for the doublet design. In the first phase of the study, the influences of the three-dimensional (3D) structures of anticlines and synclines on the temperature field were examined. A comprehensive petrophysical investigation was performed to build a large scale 3D-model of the reservoir. Several bottomhole temperatures (BHTs), as well as petrophysical logs were used to calibrate the model using thermal conductivity measurements on 50 samples from boreholes in different lithological units in the study area. Profiles and cross sections extracted from the calculated temperature field were used to study the temperature in the surrounding areas of the planned doublet. In the second phase of the project, a detailed 3D numerical reservoir model was set up, with the aim of predicting the evolution of the producer and injector temperatures, and the extent of the cooled area around the injector. The temperature model from the first phase provided the boundary conditions for the reservoir model. Hydraulic parameters for the target horizons, such as porosity and permeability, were taken from data available from the nearby exploration wells. The simulation results are encouraging as no significant thermal breakthrough is predicted. For the originally planned location of the producer, the extracted water temperature is predicted to be around 79 °C, with an almost negligible cooling in the first 50 years of production. When the producer is located shallower parts of the reservoir, the yield water temperatures is lower, starting at ≈76 °C and decreasing to ≈74 °C after 50 years of operation. This comparatively larger decrease in temperature with time is caused by the structural feature of the reservoir, namely a higher dip causes the cooler water to easily move downward. In view of the poor reservoir data, the reservoir simulation model is constructed to allow iterative updates using data assimilation during planned drilling, testing, and production phases. Measurements during an 8 h pumping test carried out in late 2010 suggest that a flow rate of 150 m 3 h −1 is achievable. Fluid temperatures of 76.5 °C were measured, which is very close to the predicted value.

The strength retrogression of special class Portland oilwell cement

Temperatures in excess of 110 ºC result in phase transformations of cement, significantly decreasing its compressive strength. This effect is referred to as strength retrogression. It is frequently observed in cement sheaths of heavy oil wells submitted to steam injection. The present study evaluated the mechanical behavior of Special Class Portland Oilwell Cement (SCPOC) slurries containing silica flour to prevent retrogression. A factorial statistical planning was used to assess the effect of the main variables on the mechanical behavior of cement slurries, i.e., mechanical testing temperature (30, 100, 120, 180 and 230 ºC); contents of silica flour replacing cement (0-18 and 36%) and curing time for rupture (12 h and 7 days). The results revealed that slurries containing 18% of silica flour tested at 230 ºC depicted an increase in compressive strength up to 30% after curing for 12 h and 10% after curing for 7 days, indicating retrogression. On the other hand, testing slurries containing silica flour at temperatures up to 180 ºC revealed strength increase of just 10%, suggesting the mechanical stability of the SCPOC, which prevents retrogression. Such behavior was probably related to the relatively low content of C3A and low specific area of the material. Therefore, strength retrogression at typical bottom hole temperatures of up to 180 ºC can be controlled by small additions of silica flour, economically contributing to the use of SCPOC cementing.

Use of High-Strength Coiled Tubing in High-Pressure/High-Temperature Perforating Operations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 143079, ’Use of High-Strength Coiled Tubing in High- Pressure/High-Temperature Perforating Operations,’ by K. Makris, SPE, and D.A. Barclay, Halliburton, and W.D. VanArnam, NOV-Quality Tubing, originally prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed. A major operating company demonstrated interest in the development of high-strength (greater than 125,000-psi yield) coiled tubing (HS CT) for use in high-pressure/high-temperature (HP/HT) fields in the central North Sea. The objective of the operator was to perforate underbalanced with CT using as much as 1,700 ft of guns in one run. The CT had to be sufficiently strong to avoid collapsing while pulling the weight of the bottomhole assembly (BHA) and the string from the working depth. Introduction During last 2 decades, more unconventional reservoirs have been targeted, such as those in HP/HT fields. An HP/HT field typically has bottomhole pressure (BHP) greater than 10,000 psi and a bottomhole temperature greater than 300°F.The reasons for targeting these fields includes the high yield of hydrocarbons they offer, which justifies the high drilling and completion costs, and the depletion of the more-conventional reservoirs in areas with well-established oilfield-support services, meaning that this already-established network can offset the increased well costs. The range of well services used in HP/HT fields includes the provision of CT services, which have proved to offer a popular way to perform certain operations in these fields, such as deploying tubing-conveyed-perforating (TCP) guns. Often, the weight of the BHA and/or the wellhead pressure after perforating prohibits running perforating guns on wireline. On the other hand, using the rig blocks to deploy, run in hole, and reverse deploy the guns can be time consuming and costly. Hence, CT often can provide a carrier solution and perform such a task faster than the rig because it is stronger and has increased potential for wellbore access when compared to wireline. However, CT is limited by the weight it can pull and the differential pressure (CT annulus vs. CT pumping pressure) it can sustain. Exceeding these limits can result in a CT failure and result in a costly and time-consuming fishing job, or even a well-control situation. While more HP/HT fields are being developed, operators are considering the use of CT to perforate deeper wells with higher wellhead pressures. For the well-intervention industry to rise to the task, the need for stronger CT is obvious.

Indonesian Fieldwide Application of Intelligent-Well Technology - A Case History

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21063, ’Indonesian Operator's First Fieldwide Application of Intelligent-Well Technology - A Case History,’ by Kim Sam Youl, and Harkomoyo, SPE, Kodeco Energy Company and Doug Finley, SPE, Halliburton, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. A fieldwide application of intelligent-well-completion technology was used in Indonesia to commingle “free energy” from an overlying gas cap to support production from underlying oil reservoirs that typically have a high water cut. Previously, wells in this offshore field were developed with conventional gas lift completions that used gas supplied from outside the platform. The application of an “auto-gas-lift” (AGL) concept, an intelligent-well technology, eliminated the capital equipment associated with conventional gas lift completions along with the conventional downhole gas lift equipment. Introduction The KE-38 field is in the East Java basin, approximately 30 miles off the northern coast of Madura Island, Indonesia (Fig. 1). Water depth averages approximately 190 ft in this block. The oil columns are between 60 and 300 ft thick, with a 500-ft-thick gas cap (on average) and an underlying water zone. True vertical depth of the gas/oil contact is 4,500 to 5,000 ft subsea. Porosity of the oil rim ranges from 18 to 26%, and permeability ranges from 20 to 100 md. The reservoir is normally pressured, and productivity ranges from 5 to 20 bbl/(psi-D). Maximum bottomhole pressure and temperature are 2,200 psi and 195°F, respectively. The oil is a slightly waxy, 35°API crude. Given that the reservoir fluid is nearly saturated, initial production from the wells was with natural flow. However, because the flowline pressure is high (approximately 900 psi), these wells would require artificial lift during the initial stage of operation to begin flow and maintain the gas/liquid ratio to optimize the produced-oil rate. Conventional gas lift completions have a setting-depth limitation relating to the gas lift mandrel. The maximum setting angle is less than 60°. However, an AGL interval-control valve (ICV) is capable of being set in any trajectory angle and can be set at the deepest point in the wellbore to optimize oil production. The AGL completion enables altering the flow characteristics of a zone without mechanical intervention.

Geothermal regime and hydrocarbon kitchen evolution of the offshore Bohai Bay Basin, North China

The offshore Bohai Bay Basin, located in the central Bohai Bay Basin, north China, one of the most petroliferous basins in China. In this article, based on formation-testing temperature, drill-stem tests, and bottom-hole temperature data, 80 thermal gradient values at the depth interval of 0 to approximately 3000 m (~9843 ft) in the offshore Bohai Bay Basin were obtained. The basinwide average thermal gradient is 31.8 4.6C/km. Based on the above thermal gradient data and the corresponding average weighted thermal conductivity data, 80 measured terrestrial heat flow values were obtained. These values range from 33.5 to 84.0 mW/m2, with an average value of 60.8 8.7 mW/m2. The heat flow and thermal gradient distribution in this region generally show higher values in the uplifts and lower ones in the sags. A thermal history, derived from vitrinite reflectance and apatite fission-track) data, indicates that Paleogene cooling occurred after a period of much higher paleogeothermal gradient (3854C/km). Tectonic subsidence analysis reveals that the area experienced initial synrift subsidence during the Paleogene followed by subsequent thermal subsidence since the Neogene. Thermal and tectonic subsidence histories of this area are of great significance to petroleum exploration and hydrocarbon resource assessment because they bear directly on issues of petroleum source rock maturation. The maturation and hydrocarbon expulsion histories of the Paleogene Shahejie 3 Formation (E2s3), which is the most important source rock in the offshore Bohai Bay Basin, are modeled. Results show that the Shahejie 3 Formation is in a high mature stage at the present day, and the Bozhong and Qikou sags are the most important kitchens. The Huanghekou sag became the third most important hydrocarbon kitchen in the early Neogene. Based on this hydrocarbon kitchen evolution, oil and gas mainly accumulated after 12 Ma. The evolution of kitchen areas may provide new insights for the understanding of the oil and gas exploration potential of the offshore Bohai Bay Basin.

Material and Completion-Equipment Selection for an HP/HT Sour-Gas-Field Development in Indonesia

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 136163, ’Material and Completion-Equipment Selection for HP/HT Sour-Gas-Field Development in Indonesia: Case Study,’ by Gustioro Purwagautama, SPE, and Rizky Andika, SPE, MedcoEnergi, and David McCalvin, SPE, and Dmitry Pleshkov, SPE, Schlumberger, prepared for the 2010 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Ho Chi Minh City, Vietnam, 1-3 November. The paper has not been peer reviewed. The Lematang Block in South Central Sumatra has estimated total reserves of 330 Bscf, with an expected production life of 10 years. Wells in this field contain 32% CO2 and 100 ppm H2S, have a bottomhole pressure (BHP) of 10,500 psi, and have a bottomhole temperature (BHT) of 408°F. The initial two wells were completed by the previous operator using 22Cr tubulars and 13Cr accessories. However, operational difficulties from material deterioration were identified. Optimization of completion durability considering economics was of high concern when selecting materials and completion-tool designs. Introduction The direct costs of completion hardware and long-term product performance to ensure durability for the life of each well were studied in detail before selections were confirmed. This study required the use of metallurgical and reservoir experts to provide opinions on material selection and required completion specialists to select the specific products to ensure that desired results were obtained. The workflow used to select the correct material and equipment culminated in a complex decision tree. Various analyses then were performed to support the selection of materials and the downhole equipment. Background To meet the growing demand for natural gas in the Far East, exploration and appraisal drilling was conducted on the Singa field in South Sumatra, Indonesia. This field has estimated gross reserves of more than 200 Bscf in a carbonate reservoir at 11,900 ft with a BHP of 10,500 psi and BHT of 408°F. Appraisal wells were drilled in 1997 and 1998. Both well tests showed similar results: 10,500-psi reservoir pressure, traces of H2S, and 32% CO2 with no water production. In 2003, the second well was completed with 22Cr tubulars, a packer, and a safety valve. After 1 year of production, the annulus pressure began to increase, indicating completion-equipment-integrity failure. Further development of the field by drilling and completing two additional wells was planned for 2008. Critical factors, including cost, corrosion rate, life of the field, equipment lead time, gas composition, pressure, and temperature, must be assessed before finding an optimum solution. Besides the 22Cr tubular that had been used, tubular-material candidates for future wells in this field were 13Cr-HP2 and 15Cr-UHP. The operator simulated the corrosion effects on the material and searched for the optimum material to use. To optimize performance and reduce the overall completion cost, a detailed study and a series of tests were performed.

Understanding and Managing Bottomhole-Circulating- Temperature Behavior in Horizontal High-Temperature Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140332, ’Understanding and Managing Bottomhole Circulating Temperature Behavior in Horizontal High-Temperature Wells - A Case Study Based on Haynesville Horizontal Wells,’ by Keith Trichel, SPE, and John Fabian, SPE, Baker Hughes, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. While high-temperature (HT) wells have always presented drilling challenges, the recent activity increase in the Haynesville shale along the border of Texas and Louisiana presents an extreme environment for drilling equipment. Along with a high frequency of temperature-related measurement-while-drilling (MWD) and logging-while-drilling (LWD) failures, the profile and architecture of Haynesville wells have provided an opportunity to study and understand the thermal behavior of horizontal HT wells in general. Thereby, well-specific operational guidelines and planning considerations can be implemented to reduce the risk of downhole temperature-related failures. Introduction The Haynesville covers approximately 9,000 sq miles. The Haynesville basin could contain up to 250 Tcf of technically recoverable gas, making it one of the largest gas plays in the USA. Production is from the Bossier and Haynesville shale formations, which correspond in many areas, so the names often are used interchangeably. The Haynesville has average thickness of 200 to 300 ft, and the depth ranges from 10,500 ft in the northwestern part of the basin to 13,500 ft in the southeastern extremities. This play is one of the deepest shale plays, and, therefore, downhole conditions are more difficult. Bottomhole temperatures (BHTs) have been measured on the order of 380°F. A typical Haynesville well requires 35 to 45 days to drill. The intermediate section may be drilled with either water-based mud (WBM) or oil-based mud (OBM), at the operator’s discretion. Soft sediments are encountered in the upper section below surface casing, but very hard and abrasive zones are found in the lower portion when passing through the Travis Peak and Cotton Valley formations. Completing the intermediate-hole section in a single polycrystalline-diamond-compact-bit run is difficult. Most horizontal sections in the Haynesville are drilled with OBM and experience high bottomhole circulating temperatures in the range of 300 to 350°F, mud weights of 15 to 17 lbm/gal, and high stand-pipe pressures of approximately 4,000 psi. The combination of OBM, high temperature, and high solids content in the mud is a challenging environment for downhole motors, but motor failure is not the leading cause of unplanned trips. Often, the high bottomhole circulating temperatures exceed the normal temperature rating of MWD/LWD electronics, typically 302°F. To address this need, some directional-service companies offer specially screened tools rated to 320°F while others offer high-temperature tools rated to 350°F. Even with this technology, recent trends indicate that the leading cause of unplanned trips in the Haynesville is likely to be failure of the MWD/LWD electronics.