International Petroleum Technology Conference Research Articles

Better Permeability Estimation From Wireline Formation Testing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18914, “Extracting More From Wireline Formation Testing: Better Permeability Estimation,” by S.R. Ramaswami, P.W. Cornelisse, SPE, H. Elshahawi, M. Hows, and C.L. Dong, SPE, Shell, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2017 International Petroleum Technology Conference. Reproduced by permission. The use of pressure-transient data in formation testing to describe reservoirs is considered mature technology, particularly when applied to data collected through production testing. The extension of this technique to data obtained using wireline formation testers (WFTs) has been gaining momentum in the industry; however, the integration of these outputs with other measurements of data is not always straightforward. The complete paper presents different methods of using pressure-transient data from WFTs; many of these methods are summarized here. Pressure-Transient Data From WFTs Perhaps the most widely used form of WFT pressure-transient data is that derived from small-volume drawdowns and buildups during a pressure test. The volume of fluid withdrawn from the formation, and the resulting depth of the pressure pulse, is limited to the near-wellbore region. The flow regime that develops during these tests is typically spherical flow in an infinite medium; hence, the mobilities derived from these sorts of pressure-transient tests are spherical mobilities and need to be converted to radial mobilities to quantitatively compare the tests. Additionally, pretest-derived mobilities have two fundamental challenges: the unknown effect of skin caused by drilling damage and the uncertainty of fluid viscosity to be used to convert the resulting mobility to permeability. The other common application of pressure-transient information during wireline-formation tests uses pressure data over a much longer interval. During an extended pumping station with a WFT, a particular flow-rate history is applied to a well and the resulting pressure changes are recorded. From the measured pressure response, and from predictions of how reservoir properties influence that response, an insight into the reservoir can be gained. In order to make these predictions, it is necessary to develop mathematical models of the physical behavior taking place in the reservoir. Fig. 1 shows the difference between the volume investigated with a small-volume pressure test and an extended pumpout station. The most-common well model that is used when interpreting WFT data is the vertical limited entry model. Fluid flow in porous media is governed by the diffusivity equation. To derive it in its simplest form, the following assumptions and simplifications have to be made: The reservoir is homogeneous, isotropic, and of constant thickness The flow is horizontal The fluid is monophasic and slightly compressible Pressure gradients are small, and Darcy’s law applies

Development of Work Flow To Manage Fatigue of Bottomhole Assemblies

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18682, “Development and Utilization of BHA-Fatigue-Management Work Flow,” by Hendrik Suryadi, SPE, and Phan Van Chinh, SPE, Schlumberger, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. A new fatigue-management work flow provides drillers with a tool to simulate and predict the life expectancy of bottomhole assemblies (BHAs) before fatigue causes problems. This new feature allows engineers to calculate and monitor the fatigue life. It also helps engineers to take appropriate action before a failure occurs downhole or to provide information to the maintenance team for preventive maintenance. Overall, this new approach allows engineers to manage drilling risks related to fatigue before any negative consequences. Introduction The oil and gas industry continues to drill wells that are deeper, more complex, and have greater extended reach and dogleg severity. These wells expose drillstring elements to higher loads and several kinds of cyclic stresses. The success of drilling operations relies on maintaining the integrity of the BHA and the drillstring. One of the more common catastrophic events related with BHA integrity is twistoff, where the BHA component parts from the drillstring downhole. Twistoff can be caused by the load exceeding the collar strength or by high shock, vibration, or corrosion, but the primary cause of twistoff is fatigue failure. With fatigue failure, the drillstring fails downhole despite the stress being below the material-strength specification. This is caused by fatigue accumulated over time. According to some reports, fatigue failure contributes to more than 60% of total drillstring failures. Fatigue failure can occur under a wide range of conditions and environments; however, a higher risk of fatigue failure always exists when rotating drill collars and tools through high-dogleg intervals during the drilling. With high rig operating costs and increasing BHA and wellbore complexity, increased focus has been placed on avoiding twistoff-related expenses such as Cost associated with time required to trip out of the hole Cost of fishing operations and to repair or replace failed equipment Cost to perform sidetracking Engineers attempt to prevent drillstring failures by optimizing the drill-string and trajectory designs.

How To Design a Bottomhole-Assembly Rotary-Speed Sweet Spot

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18836, “How To Design a BHA Rotary-Speed Sweet Spot,” by Jeffrey R. Bailey, SPE, and Andrius Minkevicius, SPE, ExxonMobil; Alexander Bolzan and Victoria R. Wilkins, Hibernia Management and Development; and Joshua S. Pokluda, Esso Exploration and Production Nigeria, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. Correct placement of the rotary-speed sweet spot of a bottomhole assembly (BHA) provides multiple benefits toward achieving the ultimate goal of drilling to section total depth in a single trip. The process of BHA redesign and tuning for the desired operating parameters provides greater control over the drilling process. Vibration minimization through proper design and operation of the BHA facilitates drilling objectives that include reaching section depth in fewer trips and providing acceptable borehole quality to run casing to depth. Introduction A musician understands the basic principle of a stringed instrument: The frequency of the note made by the instrument varies with the length of the string span. Other parameters play a role, including the string properties and tension. However, once the instrument is tuned and the concert has begun, the musical notes are played principally by changing the length of the vibrating string. As the finger position is changed on the fingerboard, the pitch of the note changes. Although this is a basic concept to a musician, it is not common today in the oil and gas industry for engineers to apply this concept to BHA design selection. A BHA is a beam that may be rep-resented by a fourth-order differential equation. Model calculations proceed by subdividing the BHA into elements comprising short sections of pipe in a lumped-parameter model. A 2D model uses a state vector at each mass node comprising the lateral displacement in a plane, tilt angle relative to the center-line, bending moment, and beam shear load. In the lateral bending flex mode, a dynamic side force is applied at the bit at integral multiples of the rotary speed. In the rotary twirl mode, offset mass elements are used to investigate the stability of the BHA to eccentric mass and centrifugal forces. The dynamic response is considered to be a perturbation from the static solution. The bending strain energy is related to the square of the bending moment in the beam, and calculating the length-averaged BHA bending energy provides a BHA bending-strain-energy vibration index. Lower values of vibration indices are sought because the dynamic response to a reference input is then minimized (i.e., lower vibrations are then predicted by the model). All such modeled designs are perturbed by identical inputs, and the model results may then be compared on an apples-to-apples basis.

Comments: How JPT Selects Technical Papers

Editor's column JPT publishes summaries of 144 technical papers a year, choosing from among more than 4,000 papers to ensure that it is publishing the “best of the best.” Although this has been standard practice for the magazine for years, many SPE members, as well as nonmembers, are unclear how these papers are selected. It starts with dedicated volunteers. The JPT Editorial Committee comprises 47 oil and gas industry professionals who are experts in their field. Committee members volunteer their time to review technical papers and abstracts that have been presented at SPE conferences as well as the multisociety Offshore Technology Conference, Unconventional Resources Technology Conference, and International Petroleum Technology Conference and identify the most relevant, high-interest, and practical papers for publication. Occasionally, papers that have not been presented at a conference but submitted directly to JPT are reviewed. Reviewers also attempt to ensure that the papers represent the industry’s geographic and corporate diversity. JPT staff then summarize the chosen papers in 2–3 pages with access to the full-length paper available online. SPE members can access the full-length papers for free for 2 months at www.spe.org/jpt. Over the course of the year, JPT will publish summaries of 12–16 papers monthly in a variety of upstream areas such as hydraulic fracturing, formation evaluation, completions, and enhanced oil recovery to name a few. The committee members have diverse positions in the industry as well as backgrounds. They include professionals at operators, service companies, national oil companies, independents, consultancies, and in academia. Qualifications to serve on the committee include SPE membership, be a recognized industry expert on a particular technical topic, have at least 10 years of experience in the oil and gas industry, and have been an author of SPE technical papers. The chair of the committee serves a 3-year term as do the committee members. Current members of the committee and their job affiliations can be found to the right of this column. The goal of publishing these technical paper summaries is to provide readers with short versions of important papers. In years past, JPT published full-length technical papers but that allowed for publication of only a few over the course of the year. Publishing summaries allows readers to be exposed to a variety of ideas and technology applications and an avenue to easily access the full-length paper if interested. This help meets JPT’s, and SPE’s, goal of disseminating and sharing knowledge about recent state-of-the-art developments, best practices, and solutions in E&P technology. Each reviewer also picks additional papers for a recommended reading list, for those interested in more high-quality information on a topic, and prepares an article on the state of the technology in that particular discipline. So far this year, the committee has reviewed 3,795 papers and will have reviewed more than 4,000 by the end of the calendar year. The process is distinct, but sometimes confused, with peer review. SPE’s online technical journals publish peer-reviewed papers, which is a more lengthy process involving industry experts carefully evaluating a paper and working with the author to clarify or validate certain assumptions or statements.

New Magnetite Nanoparticles Allow Smart Drilling Fluids with Superior Properties

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18731, “A Comprehensive Approach for the Development of New Magnetite Nanoparticles Giving Smart Drilling Fluids With Superior Properties for HP/HT Applications,” by Z. Vryzas, Texas A&M University at Qatar; V. Zaspalis, Aristotle University of Thessaloniki; L. Nalbantian, Centre for Research and Technology Hellas; O. Mahmoud and H.A. Nasr-El-Din, Texas A&M University; and V.C. Kelessidis, Texas A&M University at Qatar, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. This work focuses on using custom-made (CM) magnetite (Fe3O4) nanoparticles (NPs) to improve the properties of bentonite-based fluids. The microstructure qualities and modes of interaction have been identified, helping to optimize the rheological and fluid-loss properties of these drilling fluids. The better performance of the CM Fe3O4 NPs can be attributed to their extremely small size, which leads to stability in suspensions and effective linking with the bentonite particles, thus allowing the formation of a rigid microstructure network. Introduction The effects of adding iron oxide NPs on the rheological and filtration properties of aqueous bentonite suspensions have been studied by several researchers. The results showed that the addition of iron oxide NPs at low concentrations significantly improves drilling-fluid-filtration characteristics and maintains optimal rheological properties compared with the base fluid (BF). Moreover, the creation of a thin and impermeable filter cake and its effectiveness depend on the NP concentration. The main objective of the research detailed in the complete paper is to study the performance of aqueous bentonite suspensions (7 wt%) containing CM Fe3O4 NPs at 0.5 wt% concentration in terms of their rheological and fluid-loss properties. Rheological analysis for the fluid samples with and without dynamic thermal aging identifies the degree of thixotropy of the developed fluids. The study outlines the effect of temperature on the yield stress, presents an integrated approach to characterizing raw materials by use of various methods, and explores techniques used to examine the produced-filter-cake properties and the size of NPs. Combination of such an integrated analytical approach regarding the evaluation of the properties of such suspensions together with the development and use of CM Fe3O4 NPs with made-to-order properties can lead to the development of multifunctional smart drilling fluids. The results of the experiment are discussed in detail in the complete paper. Experimental Materials and Sample Preparation. The bentonite, in powder form, had a relative density of 2.6 g/cm3 and was supplied without any polymer additives. It was tan in color with a pH range of 8–10. X-ray-diffraction (XRD) and X-ray-fluorescence analyses confirmed that the bentonite was sodium-based, with small quantities of illite and quartz. The bentonite had a mean particle size of 36 µm.

3D Full-Field and Pad Geomechanics Models Aid Shale Gas Field Development in China

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18984, “Three-Dimensional Full-Field and Pad Geomechanics Modeling Assists Effective Shale Gas Field Development, Sichuan Basin, China,” by Liang Xing, PetroChina; Xian Chenggang, SPE, Schlumberger; Shu Honglin, PetroChina; Chen Xin, Schlumberger; Zhang Jiehui, PetroChina; Wen Heng, Schlumberger; Wang Gaocheng, PetroChina; and Wang Lizhi, Guo Haixiao, Zhao Chunduan, Luo Fang, and Qiu Kaibin, SPE, Schlumberger, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. The oilfield-development plan (ODP) for a shale gas field at the southern edge of the Sichuan Basin in China started in early 2014. The first wells drilled in the field and its adjacent blocks experienced significant challenges, such as severe mud losses, stuck tools, losses in the hole, high treating pressure, and unexpected screenout. Because an accurate understanding of geomechanics and its roles at various scales is vital, 3D full-field and pad geomechanics models were developed for achieving efficiency and effectiveness in implementing the ODP. Introduction The Ordovician-Silurian Wufeng-Longmaxi hot shale is an emerging shale gas play in China. Currently, the major exploration and development activities of the play are in the Sichuan Basin and its adjacent areas. For shale gas development in the Sichuan Basin and its adjacent areas, using the megascale, high-density, and continuous and regular pad drilling as is used in North America is difficult because surface and subsurface conditions are significantly different from those of the well-known North American shale plays. The strong environmental and social constraints that typify the Sichuan Basin and surrounding area are shown in Fig. 1. Drilling pads for shale gas developments are commonly located in narrow valleys that are often home to farmland and residential villages with dense populations. Differences of elevation among neighboring pads can be from several hundred meters to more than 1000 m. To speed up development of marine shale gas in the Sichuan Basin and its adjacent areas with a minimized learning curve, a geoscience-to-production integration of research, engineering, and operation with its associated research and development, methodologies, and work flows must be applied. This geoscience-to-production integration aims to optimize both efficiency and effectiveness dynamically at single-well, pad, and field scales with systematic and continuous optimization of technologies and solutions and the accumulation of knowledge and experience to enhance well productivity. One shale gas field, which is the study area of this paper, is in the mountainous area at the southern edge of the Sichuan Basin. The first wells drilled in this field and its adjacent blocks experienced significant geomechanics-associated challenges, such as severe mud losses, tools or drillingpipe sticking, losses in the hole, high treating pressure while hydraulic fracturing, and unexpected screen out of fracturing stages. Having reliable yet evolving understanding of geomechanics and its role at various scales during the progress of the ODP is vital. This paper describes the development of 3D full-field geomechanics models and high-resolution 3D pad geo-mechanics models and their engineering applications.

Method Addresses Difficulty of Modeling Heterogeneous Carbonate Bimodal Rocks

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18587, “Heterogeneous Carbonates: A Modeling Method Ensuring Consistency Between the Saturation-Height and Permeability Models for Bimodal Rocks,” by Iulian N. Hulea, Harm Dijk, SPE, Danila Karnaukh, and Mirano Spalburg, Shell, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. Because of their heterogeneity, carbonate reservoirs are more difficult to model than clastic reservoirs. The main difficulty comes from the number of different pore types, compared with the typical interparticle pore type in clastics. By using saturation-height models (SHMs) in combination with conventional permeability measurements, a new approach attempts to extract the fundamental properties of individual pore systems. The key idea centers on identifying the governing pore systems from capillary pressure curves and permeability measurements. The approach results in the ability to predict permeability continuously as a function of pore-system mixing ratios. Introduction Because of the presence of multiple pore types, carbonate rocks are difficult to model. To account for their heterogeneity, carbonate rocks are often modeled using rock-typing schemes. Two particularly challenging properties are permeability and saturation. Although these properties have been recognized as being closely connected, little information is available on how to handle them consistently. Even when permeability and SHMs satisfactorily describe the core measurements, it is not trivial to ensure their consistency in 3D models. One possible situation is building SHMs that impose consistency through the governing parameters. Throughout this work, a Brooks-Corey function is used because it was found to describe unimodal mercury-injection capillary pressures (MICPs) satisfactorily. For the examples discussed in this contribution (Fig. 1), microporosity (corresponding to the pore system accessible beyond pore throats of 2 µm or less) forms between 40 and 70% of the pore volume and is mostly located within the micritic grains. A significant difference between the two examples shown in Figs. 1a and 1d is the relative contribution of microporosity on average equaling 0.53 for Rock Type 1 (RT1) and 0.75 for Rock Type 2 (RT2). For RT2, microporosity can be located in the mud between the grains. Capillary Pressure Curve Data Analysis and Modeling The MICP modeling strategy relies on treating the two pore systems as independent, fitting each one of the pore systems first then looking for the best correlation to predict the Brooks-Corey parameters. On the basis of the measured individual-core-plug properties, the standard deviation for both plug porosity and the relative ratio of microporosity to total porosity was derived. By making the plots with the same fundamental inputs (SHM, porosity, permeability transform), the properties predicted by the models can be highlighted and contrasted.

Novel Coiled-Tubing Perforation Technique and Stimulation in Carbonate Gas Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18880, “Novel Abrasive Perforating With Acid-Soluble Material and Subsequent Coiled-Tubing Jetting-Assisted Stimulation Provide Outstanding Results in Carbonate Gas Well,” by Adrian Buenrostro, Nahr Abulhamayel, Usman Malik, Mohammad Bu Suwaileh, and Saad Driweesh, Saudi Aramco, and Alejandro Chacon, José Camilo Jimenez Fadul, and José Noguera, Halliburton, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. Abrasive perforating with coiled tubing (CT) is a technique that has proved to be a valuable alternative to conventional perforating with electric line. The application is particularly valuable whenever a high rate or fracture-stimulation treatment is to follow because of the significant reduction in tortuosity and pumping friction losses across perforations. This paper discusses a novel approach to abrasive perforating, including the first-ever use of an acid-soluble abrasive material and ending with CT-jetting-assisted nitrified stimulation. Introduction Many carbonate gas wells located in the northern section of the Ghawar reservoir exhibit a low-permeability profile and are characterized by having low reservoir pressure. Fracture gradients in a formation in this area of the field are on the order of 1.12 psi/ft, which is considerably greater than that of more-conventional tight gas formations. One particular well, located on the flank of the reservoir, was designed to be completed with a plug-and-perforate acid-fracturing operation, but issues arose with this option that finally caused the abandonment of the fracturing treatment. To find a solution that would be feasible and economically viable, an innovative perforation and stimulation technique was engineered for this well. Design of the Perforation Technique and Yard Testing The team was able to source a newly developed acid-soluble abrasive material that enabled the same quality of perforations to be created without performing a cleanout run because the acid from the stimulation would dissolve the abrasive material, saving at least 2 days of operation. The abrasive material was sourced, and several yard tests were completed to determine if the material had the same abrasive characteristics as common 20/40- or 100-mesh sand. It was necessary to compare the time required to penetrate the steel and cement with the results obtained using common sand. This benchmarking was key to determining if additional time and fluid resources were necessary to obtain the same penetration. A yard test was set up with two metallic 55-gal drums cut halfway lengthwise and then welded together. This created a receptacle that allowed the team to place a 6⅝-in. casing section with 100% standoff and then fill the entire annular space with cement. The drum was then set on top of cement blocks, and the abrasive-jetting tool was introduced.

Integrated Approach for Overpressure Prediction in an HP/HT Well Offshore Malaysia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18909, “An Integrated Approach for Overpressure Prediction in a Wildcat High-Pressure, High-Temperature (HP/HT) Exploration Well Offshore Sarawak, Malaysia,” by Avirup Chatterjee, Amitava Ghosh, and Sanjeev Bordoloi, Baker Hughes, and Anifadora Bt. Mustapha, Petronas, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. Pore-pressure prediction plays an important role in well planning as exploration targets shift to deeper, overpressured reservoirs. Pressure-related problems in such zones are mainly associated with narrow operating windows, resulting in severe well-control incidents, sometimes even leading to early abandonment. Uncertainties in prediction models arise from input data, assumptions used in the work flow, and the complexity of the geological or structural conditions. It is important to analyze these uncertainties and develop an understanding of them before drilling. Introduction Central Luconia is a geological province of the Sarawak Basin characterized by extensive development of Miocene to Holocene carbonate buildups. The buildups reveal complex seismic geomorphologies, facies, and structural setting. There have been several discoveries in the shallow-water (approximately 90-m depth) area of central Luconia province offshore Sarawak. A predrill pore-pressure- and fracture-gradient-prediction study was initiated for a planned high-pressure/high-temperature (HP/HT) well with three offset wells (Offsets 1, 2, and 3) drilled in the vicinity of the study area. The objective of the study was to help in well design to reach desired deeper target reservoirs. The prospect is situated in a structure characterized by a northwest/southeast normal fault. It was formed on the foot wall block for the shallow (post-carbonate clastic) reservoirs and crossing the fault to the hanging wall block to hit the main targets in deeper (precarbonate clastic) cycles. The lithology for the shallow cycles is interbedded fine-grained siliciclastic shale and sand with limestone streaks. The deeper cycles consist of predominantly sandstones with interbedded shales. Two offset wells (Offsets 2 and 3) penetrated a thick carbonate sequence, and the other offset well (Offset 1) encountered a thick sand/shale sequence with interbedded carbonate stringers, which is similar to the prognosed-well result. Therefore, in the predrill modeling, there was only one relevant offset well (Offset 1) available in the study area that penetrated similar lithostratigraphic units. Well Issues A detailed analysis of all the drilling problems encountered in the offset wells was catalogued. This was achieved by reviewing the daily drilling reports, final well reports, and mud-logging reports and documenting all the events on a daily basis. Overall, all the offset wells analyzed during the study indicated several drilling issues related to pore pressure, including internal blowout with violent gas flow from the bell nipple, influxes, gas-cut mud, high gases, connection gases, pumps-off gas, and cavings. In addition, wells showed significant challenging drilling conditions such as equivalent static- and circulating-density contrast because of high temperature, wellbore breathing caused by a narrow mud window, and several hole-stability issues such as tight hole, lost circulation, and stuck pipe, eventually leading to multiple sidetracks.

3D Close-the-Loop Method Based on Probabilistic Seismic Inversion

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18913, “3D Close the Loop Using Probabilistic Seismic Inversion for a Gas Field in the Carnarvon Basin, Australia,” by Shilpi Srivastava, Jeroen Goudswaard, Sito Busman, and Justin Ugbo, Shell, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. The paper discusses an approach for predicting the lateral variation of net to gross (NTG) by use of 3D probabilistic seismic inversion. The goal is to define and understand the distribution of sands and shales on the basis of seismic reflection data. The modeling and inversion are supported by the good quality of seismic data. This study underpins the benefits of seismically constrained reservoir modeling. The use of probabilistic inversion to map geological features is a new insight in the applicability of this methodology. Introduction The study field is located in the Carnarvon Basin offshore western Australia. The field was appraised with one well, which has added incremental volumes to existing nearby discoveries. Seismically constrained reservoir-model building creates models that are constrained by, and matched to, geological concepts and seismic amplitudes and travel times. The complete paper shows an approach using 3D probabilistic seismic inversion to predict the lateral variation in NTG over a proven discovery. This, in turn, can be used to update the static-model properties, improving on the first-pass static-model build. Additionally, the inversion will aid in the understanding of some poorly understood seismic expressions, especially in the south of the field. In this area, the authors noticed dim amplitudes on the amplitude maps extracted from the seismic data, where the static model predicts the presence of the reservoir. Field The field is located in the Carnarvon Basin. The discovery was appraised by one well, which penetrated a thin sand layer of interdistributary bay reservoir facies (referred to as Sand 1) and a thicker distributary channel facies (referred to as Sand 2). The overburden comprises basinal shales and marls. The main steps in the 3D close-the-loop work flow are The rock-property-trend models are derived using the available vertical wells in or near the field. A “rock model” is a set of equations that honors well data and links the petrophysical properties such as NTG and porosity with rock acoustic properties. A qualitative 3D check-the-loop (CTL) step is carried out. This involves the initial fit of the static model with the seismic data by forward modeling the synthetic seismic computed from the initial static model before inversion. The quality-control step that follows aims to detect mismatches between seismic and synthetic data. Finally, constrain the reservoir model by use of the seismic data by carrying out 3D probabilistic inversion of the key uncertain rock property.

E&P Notes (January 2017)

E&P Notes (January 2017)

Tapping Difficult Oil in a Giant Carbonate Field in Qatar

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18296, “Tapping the Difficult Oil and Enhancing Reservoir-Development Strategy To Maximize Recovery From a Mature Waterflood Giant Carbonate Field in the Middle East: Arab C Reservoir, Dukhan Field, State of Qatar,” by Mohamed Naguib Bin Ab Majid, Carlos Troconiz, Mohammed Nedham Al-Shafei, Gheorghe Luca, and Ariel Cachi, Qatar Petroleum, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. After 70 years of production, more than 30% of the Arab C reservoir stock-tank original oil in place has been recovered through various mechanisms including natural depletion, waterflooding, gas lift implementation, and horizontal-well development. Extending production into future years requires a strategic approach focusing on innovative development to target the remaining oil saturation. Integration of a recently acquired, high-resolution 3D-seismic survey complements the data available for subsurface description and characterization, positively affecting reservoir-model history-matching metrics. Introduction The large, mature Dukhan field is located onshore Qatar, approximately 80 km west of Doha. The Arab C reservoir interval is a carbonate anticlinal structure lying 5,500 to 7,000 ft below the surface. Areally, the Arab C reservoir has been divided into four structural elements from north to south (i.e., Khatiyah, Fahahil, Jaleha, and Diyab). The first three sectors comprise the continuous oil-bearing extent of the reservoir, while Diyab is water-bearing on the basis of results from wells drilled to date (Fig. 1). Arab C is an undersaturated-oil reservoir. The original oil column ranged from 1,400-ft thickness in the Khatiyah sector to 400 ft in the Jaleha sector. It has a weak to moderate connected aquifer lying below the oil column. Arab C development started with vertical wells, initially completed openhole. Increase in water production led to a well-completion-scheme change; vertical wells were then completed cased-hole and perforated selectively. Horizontal drilling commenced in 1992 to improve recovery and enhance production. As the water front from injection progressed, gas lifting in Arab C was initiated in 2003 to continue producing the high-water-cut wells. Currently, 60% of the Arab C producers are flowing under gas lift assistance. Reservoir Description Arab C is a heterogeneous organization of limestone and dolomite lithologies deposited on a shallow-water Jurassic ramp system. Hydraulically, the 80-ft-thick interval represents a net-work of grainstone conductors compartmentalized by muddy carbonate baffles resulting in layer-constrained dynamic behavior. Lateral ranges of 1 to 4 km for baffling thin beds support a localized layer-constrained dynamic behavior and a high degree of vertical heterogeneity, though communication pathways are impacted by sporadic occurrences of cross-cutting conductive and resistive faults. Reservoir porosity is 15 to 20%, and the average permeability is approximately 150 md, but this varies widely on the basis of reservoir zone.

Fit-for-Purpose Treatment of Produced Water for Hydraulic Fracturing in the Permian Basin

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18340, “Fit-for-Purpose Treatment of Produced Water for Hydraulic Fracturing—A Permian Basin Experience,” by Ramesh Sharma, SPE, Kristie McLin, SPE, Kevin Bjornen, SPE, Austin Shields, SPE, Zakir Hirani, and Samer Adham, SPE, ConocoPhillips, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. Sourcing water for large multifracture stimulations in west Texas is a well-known constraint on oil and gas activities in the area. A 6-month pilot operation demonstrated that produced-water reuse is technically feasible and can be a cost-effective solution. A fit-for-purpose treatment scheme was created to remove free oil, suspended solids, hydrogen sulfide, and iron and to render microorganisms inactive. The technical approach developed allowed for the use of salty produced water for completion activities using a new type of friction reducer. Introduction The oil and gas industry has identified water management as one of the top challenges for energy extraction from unconventional resources. In the Permian Basin, surface water and groundwater resources are scarce and large multifracture stimulations regularly require more than 100,000 bbl of water per well. The Texas Railroad Commission also employs a geologist to assess seismicity at water-disposal facilities. Because of these challenges, many operators in the Permian Basin have begun to investigate and implement produced-water reuse. Produced-water-reuse initiatives executed in early 2014 paved the way for full-field produced-water-reuse implementation. The water- management team identified that produced- water reuse could significantly reduce effects to the limited water resources in the Permian Basin and help achieve sustainable- development objectives for the company. Several wells were identified as suitable candidates for the pilot because they were designed to be stimulated with a slickwater/crosslink base fluid. Additionally, these new wells were being developed in the proximity of existing producing wells, so the produced water from the existing wells can be treated easily and used to complete the new wells. The team selected multiple wells from conventional and unconventional assets to qualify water-treatment and stimulation chemistry technologies for produced-water reuse.

A New Approach for Optimization of Long-Horizontal-Well Performance

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18372, “A New Approach for Optimization of Long-Horizontal-Well Performances,” by Abdullah Al Qahtani, Hasan Al Hashim, and Hasan Al Yousef, King Fahd University of Petroleum and Minerals, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. Initially, it was believed that a horizontal well should be drilled with as much length as possible. However, field experience and flowmeter surveys in long horizontal drainholes revealed that the frictional pressure loss in the wellbore is an important factor hindering the full use of the entire length of the horizontal well. This paper presents a new approach to maximize the use of the full length of long horizontal drainholes. Introduction Horizontal-well drilling allowed the drilling of different well architectures and made it possible to offset well costs and productivity limitations. Intuitively, drilling longer wells will maximize exposure to the producing formation and yield higher flow capacity. Paradoxically, however, some wells were drilled longer than the optimal horizontal-section length and the extra length did not yield additional flow. Therefore, it is important to determine the optimal horizontal-section length that would achieve flow contribution along the whole section. Experience has revealed that long horizontal wells suffer from frictional pressure losses. This fact is exacerbated in the presence of highly productive formations; these would require low pressure drawdowns that may well be similar to the frictional pressure losses, which would therefore hinder wellbore flow ingress. Thus, some horizontal wells are equipped with downhole flow-choke systems to optimize well productivity. Finite-Conductivity Horizontal Wells Horizontal wells are initially deemed to be infinite-conductivity wellbores; this thesis was made on the basis of the fact that the magnitude of the pressure drop in the wellbore is negligible. Practically speaking, however, production data proved otherwise; frictional pressure losses in horizontal wellbores hinder flow influx to different degrees along the horizontal section. This issue is of great importance under conditions in which the magnitude of the pressure drop in the wellbore is small when compared with the magnitude of the pressure drop in the reservoir. Therefore, given the fact that horizontal wells are often proposed and justified on the premise that high production rates can be obtained by small reservoir pressure drops, and the fact that flow developed at reasonably high production rates should cause increased wellbore pressure losses, the use of the infinite-conductivity assumption for horizontal wells may not be valid.

Development of Novel Drilling-Fluid Nanoparticles for Enhanced Drilling Operations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18381, “Development and Testing of Novel Drilling Fluids Using Fe2O3 and SiO2 Nanoparticles for Enhanced-Drilling Operations,” by Zisis Vryzas, Texas A&M University at Qatar; Omar Mahmoud and Hisham A. Nasr-El-Din, Texas A&M University; and Vassilios C. Kelessidis, Texas A&M University at Qatar, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. This work focuses on the laboratory techniques for developing, assessing, and analyzing innovative water-based drilling fluids containing iron oxide (Fe2O3) and silica (SiO2) nanoparticles. The examined nanoparticles have the potential to significantly improve the characteristics of the filter cakes at both low-pressure/low-temperature (LP/LT) and high-pressure/high-temperature (HP/HT) conditions. They also have the ability to maintain optimal rheological properties so that many drilling problems can be mitigated efficiently. Introduction Drilling-fluid loss is considered the major source of capital expenditure during drilling operations. Nanoparticles have proved to be more effective in reducing the filtrate losses than conventional fluid-loss reducers. Because they exhibit different adsorption and transportation behavior in different porous media, nanoparticles have been used successfully as stabilizers in emulsions and foams, as rheology modifiers, and as fluid-loss additives in surfactant/polymer or water-based drilling fluids. Addition of Fe2O3 and SiO2 nanoparticles can improve or at least maintain fluid properties even at high temperatures. This work aims to find the optimal concentration of such nanoparticles. Experimental Procedure Materials and Sample Preparation. Bentonite was supplied in powder form; the water/bentonite suspension gives a mixture with a pH range of 8 to 10. The Fe2O3 nanoparticles were purchased in powder form with a spherical shape and an average diameter of less than 50 nm with a purity greater than 97%. Nanosilica was purchased in powder form with a spherical shape and an average diameter of 12 nm with a purity greater than 99.5%. Deionized water with pH range 6.8 to 7.2 was used along with the bentonite to prepare the base fluid. All the prepared samples had pH in the range of 7.9 to 8.3. The preparation of the samples was carried out following American Petroleum Institute (API) standards. The base fluid (BF) was formulated with a bentonite concentration of 7.0 wt% in 600 cm3 of deionized water. Different concentrations of Fe2O3 and SiO2 nanoparticles were used (0.5, 1.5, and 2.5 wt%). First, bentonite was added to deionized water and mixed for 20 minutes. The desired concentration of nanoparticles was added slowly to minimize the agglomeration, and mixing continued for 20 more minutes. The samples were then sealed in plastic containers and left for 16 hours at room temperature for the bentonite to hydrate.

Mitigating Drilling Dysfunction With a Drilling Advisory System

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18333, “Mitigating Drilling Dysfunction With a Drilling Advisory System: Results From Recent Field Applications,” by Gregory S. Payette, SPE, Darren Pais, SPE, Benjamin Spivey, SPE, and Lei Wang, SPE, ExxonMobil Upstream Research Company; Jeffrey R. Bailey, SPE, and Paul Pastusek, SPE, ExxonMobil Development Company; and Michael Owens, XTO Energy, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. The ExxonMobil Drilling Advisory System (DAS) is a rig-based drilling-surveillance and -optimization platform that encourages regular drilloff tests, carefully monitors drilling performance, and provides recommendations for controllable drilling parameters to help improve the overall drilling process. Key technical components of the DAS include high-quality adaptive filtering algorithms for computing various drilling-system-performance measures, data-encapsulation/ dimensionality-reduction techniques, and reduced-order-modeling techniques that are ultimately used to generate recommendations for improved performance. Introduction Approximately a decade ago, the company initiated an internal program to pursue real-time rigsite mechanical-specific- energy (MSE) surveillance. MSE, a quantity initially developed and applied in the mining industry and subsequently applied to oilwell drilling, provides a measure of the energy required for a drilling assembly to drill through an interval of subterranean formation; and underefficient drilling conditions correlate with the compressive strength of the rock being drilled. It was quickly demonstrated that frequent drilloff tests using MSE trends to maximize drilling performance were an effective means of optimizing the drilling process. The basic idea was to use MSE trends to identify and respond to drilling-system- performance limiters such as bottomhole-assembly (BHA) whirl, bit balling, and stick/slip, with the ultimate goal of producing consistently better and longer bit runs. The initial program was deemed highly successful and since has become a key component of the rate-of-penetration (ROP) -optimization process.

New Optical Gas-Imaging Technology for Quantifying Fugitive-Emission Rates

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18471, “New Optical Gas-Imaging Technology for Quantifying Fugitive- Emission Rates,” by Hazem Abdel-Moati, ExxonMobil Research Qatar; Jonathan Morris and Yousheng Zeng, Providence Photonics; Petroula Kangas, ExxonMobil Chemical Europe; and Duane McGregor, ExxonMobil Research and Engineering, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Optical gas-imaging (OGI) technology has been developed and can be used to detect leaks of volatile organic compounds (VOCs) from process equipment. Using OGI to detect leaks is more effective than using the US Environmental Protection Agency’s Method 21 because OGI is visual, making detection faster, and can survey an area instead of one component at a time. Although OGI can be very effective in detecting leaks, it does not provide a quantitative measure of leak rate (LR), hindering its adoption as a true alternative to Method 21. This paper describes development of quantitative OGI (QOGI) technology. Method and Preliminary Results Approaches have been proposed to establish a quantitative relationship between the pixel intensity difference with and without a plume (ΔI) and the product of concentration in ppm and path length in meters (ppm·m) for a gas column represented by a pixel in the infrared (IR) image for a given temperature differential (ΔT) between ambient air and the background. This quantitative relationship has been confirmed with a study showing that there is a monotonically increasing relationship between ΔI and concentration for uniform black background that was temperature controlled. That study’s data also showed that ΔI increases as the temperature of the background increases for a specific gas concentration.

A Portfolio of Commercial-Scale Carbon-Capture-and-Storage Demonstration Projects

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18469, “A Portfolio of Commercial-Scale CCS Demonstration Projects,” by W. Maas, M. de Nier, T. Wiwchar, and B. Spence, Shell, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. A major oil company is progressing a portfolio of commercial-scale carbon-capture-and-storage (CCS) demonstration projects covering an array of technologies that target applications of relevance to the wider oil and gas industry. A number of key learnings have been obtained on the technology-deployment and the critical-project- development aspects of the different project phases. This paper provides an overview of these learnings, with a specific focus on the issues faced by CCS-project developers. Introduction Over the last decade, the company, with its partners, has been helping to advance CCS through a series of CCS demonstration projects. The operator’s CCS commercial and project portfolio includes The Quest project, which is the first CCS project of commercial scale in the heavy-oil industry The Peterhead CCS project, which, if realized, could be the world’s first commercial-scale, full-chain project to demonstrate the feasibility of CCS at a gas-fired power station This paper explores in detail the Quest project and the Peterhead project, the latter being currently in the front-end engineering and design phase. The Peterhead CCS Project The company and a UK power provider are developing the Peterhead CCS Project (Fig. 1). The scope of the project includes Operation of an existing gas turbine (GT 13) at the Peterhead Power Station in Aberdeenshire, Scotland A new steam turbine dedicated to low-pressure steam generation Capture of approximately 1 million t/a of carbon dioxide (CO2) emissions, for a period of 10 to 15 years, from the flue gas in a large concrete absorber tower using the operator’s amine-capture technology Regeneration of the amine in a tower using steam from the power plant Compression and conditioning (oxygen and water removal) of the CO2 Transport of the dense-phase CO2 by an offshore pipeline approximately 100 km in length Injection of the CO2 with the adapted Goldeneye platform and wells Storage in the depleted Goldeneye gas reservoir at a depth of more than 2 km under the floor of the North Sea The objective is that the power plant, combined with the CCS chain, will operate as one integrated low-carbon power-supply chain.

Miscible and Immiscible Gas-Injection Pilots in a Middle East Offshore Environment

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18513, “A Case Study on Miscible and Immiscible Gas-Injection Pilots in a Middle East Carbonate Reservoir in an Offshore Environment,” by Jitendra Kumar, Pawan Agrawal, and Elyes Draoui, Abu Dhabi Marine Operating Company, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Hydrocarbon-gas injection improves microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can affect the ultimate recovery negatively because of viscous fingering and gravity override. This paper describes a gas-injection pilot that has been implemented in offshore Middle East carbonate reservoirs (a second pilot is described in the complete paper) to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. Introduction The carbonate field is part of the Lower Cretaceous Lower Lekhwair formation. The field is divided into A, B, and C reservoirs, 20 to 35 ft thick individually. Each reservoir is vertically separated by nonpay tight intervals of similar thickness, composed of argillaceous limestone, isolating each reservoir from the others. Depending on the reservoir, oolitic shoal facies can be more abundant. Near the flank area, the formation is water-wet, and, as one moves toward the crestal area, the formation becomes oil-wet. The reservoir fluid is undersaturated at initial pressure of 4,200 psig at datum depth and a temperature of 220°F. Oil gravity is 40 °API, and oil contains 1–2 mol% carbon dioxide and an insignificant amount of hydrogen sulfide. All three reservoirs have common contact and similar oil properties, with a strong compositional gradient. Production from the field started in the late 1960s through natural depletion, which indicated weak aquifer support. Before pilot implementation, laboratory experiments were performed to determine the feasibility of hydrocarbon-gas injection. Pressure/volume/temperature experiments showed that the minimum miscibility pressure (MMP) is approximately 4,500 psia, which is higher than initial reservoir pressure, but the crude oil has a strong swelling effect. Unsteady-state coreflood experiments performed with a 200-cm-long core showed a recovery of 70% for immiscible flood and a recovery of 92% for miscible flood. Full-field compositional simulation of gas injection incorporating a tuned equation of state indicated significant incremental oil and reasonable pressure support.

Sandstone-Acidizing System Eliminates Need for Preflush and Post-Flush Stages

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18571, “Retarded HF System To Deeply Stimulate Sandstone Formation and Eliminate the Need for Preflush and Post-Flush Acid Stages: Experimental and Field Cases,” by Ahmed M. Gomaa, SPE, Sergey Stolyarov, and Jennifer Cutler, SPE, Baker Hughes, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. The goal of sandstone-matrix acidizing is to remove siliceous particles that are blocking or bridging pore throats. This is accomplished by injecting acid formulations containing hydrofluoric acid (HF) or its precursors because HF is the only common acid that dissolves siliceous particles sufficiently. Standard treatments include preflush and post-flush stages of hydrochloric acid (HCl) to minimize the potential for secondary precipitation. This paper presents experimental and field-case studies with a sandstone-acidizing treatment designed to retard the HF reaction rate and enable single-stage treatment. Introduction The goal of sandstone-matrix acidizing is to dissolve damage that blocks or bridges pore throats in the formation matrix, thus ideally restoring the original reservoir permeability. HF is the only common, inexpensive mineral acid able to dissolve siliceous minerals. Therefore, any sandstone acid system contains HF in some form. Mud acid, which is composed of HCl and HF, is used commonly to remove the formation damage in sandstone reservoirs. Three main steps are involved in conventional sandstone-matrix treatment: preflush, main acid stage, and post-flush. In the main acid stage, mixtures of mud acid have been used extensively in the field. In mud acid, the role of HF is to dissolve aluminosilicates and silica, while HCl helps keep reaction products soluble in spent acid. To overcome some of the potential problems associated with sandstone acidizing, a one-step sandstone acid system was developed. The new acid system will eliminate the need for preflush and post-flush HCl stages, reduce the treatment complexity, reduce the HCl requirements, and reduce the overall treatment rig time. A coreflood study was conducted with different sandstone cores at 180°F. One-Step Sandstone Acid Because of the variation in mineralogical composition of the formation being treated, an inherent risk is always involved in sandstone acidizing. In an effort to mitigate any problems, the new system contains a higher ratio of HCl to HF than conventional sandstone acid systems, which reduces the pH of the HF mixture to levels at which some unwanted reaction products have higher solubility. Four fluid formulations were selected for testing as one-step sandstone acid systems. Selection was based on HCl-/HF-concentration ratio as follows: Acid A is equivalent to 15 wt% HCl and 1.9 wt% HF. Acid B is equivalent to 10 wt% HCl and 2.3 wt% HF. Acid C is equivalent to 5 wt% HCl and 2.6 wt% HF. Acid D is equivalent to 3 wt% HCl and 2.8 wt% HF. Regular Sandstone Acid Coreflood Experiments 1 through 4 were conducted to investigate the effect of using preflush and post-flush stages of HCl when using the regular sandstone acid. In these experiments, Bandera sandstone cores were used. The regular sandstone acid system evaluated in this study contains 3 wt% HF.