International Petroleum Research Articles

Broadband Seismic Acquisition: Implications for Interpretation and Reservoir Models

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18075, “The Impact of Broadband Seismic Acquisition and Implications for Interpretation and Reservoir-Model Building,” by Carter Gehman and Andrew Spedding, Hess, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. This paper addresses the impact of acquiring a new 3D broadband seismic survey over an amplitude-supported, discovered gas field containing legacy 3D conventional towed-streamer seismic data. The new seismic data were acquired in shallow water depths by use of a dual-level streamer technique and were processed through prestack depth migration (PSDM). Five gas discovery/ appraisal wells existed before broadband acquisition, and two wells were drilled after acquisition was completed. These seven wells serve as control points that provide a valuable link between the seismic and reservoir properties. Introduction and Background Seismic imaging of hydrocarbon reservoirs with small impedance contrasts relative to bounding lithologies is challenging. Ideally, an infinite bandwidth wavelet would detect and resolve subsurface geology as observed in the resolution of a typical wireline log. Improvements in seismic acquisition and processing continue to strive toward this ideal condition, and recent advancements in seismic acquisition— namely, the broadband acquisition technique—have attempted an approximation of the infinite bandwidth wavelet through the removal of the receiver or source ghosts. This advancement is of particular interest in oil and gas development areas where known thin or poor-quality reservoirs that are difficult to detect on conventional seismic records have been penetrated by previous wells. The study area is located in the shallow (less than 200 ft) waters off peninsular Malaysia. Seven exploration and appraisal wells have targeted shallow and deep reservoirs, although only three wells have been drilled to deep targets. Generally speaking, seismic imaging of shallow reservoirs is good, while deep targets are more challenging to image. The primary motivation for acquiring a new broadband seismic survey stemmed from imaging difficulties of thin (less than 15 ft) deep gas reservoirs on conventional seismic data. Many of these reservoirs are vertically juxtaposed by coals, which tend to mask the acoustic response of the reservoir. Even after later reprocessing of legacy data through anisotropic PSDM, imaging difficulties remained.

Rod-Shaped-Proppant Fracturing Boosts Production and Adds Reserves

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18086, “Novel Rod-Shaped-Proppant Fracturing Boosts Production and Adds Recoverable Reserves in Indonesia During Hydraulic-Fracturing Field-Revival Campaign,” by L. Soetikno and P. Artola, Schlumberger, and C. Guimaraes, Chevron, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. In a fracturing campaign of three wells at Field X, a new unconventional proppant technology—a rod-shaped proppant—was used. The rod-shaped proppant is a high-strength ceramic proppant with an unconventional rod shape that has the unique benefit of delivering increased proppant-pack conductivities, higher and cleaner fracture length, and improved proppant-flowback control. After 6 months of production, all fractured wells in which the rod-shaped proppant was used delivered, on average, 25% higher oil per net pay compared with offset wells fractured with conventional proppant. Introduction Field X is a mature-waterflood field in the Central Sumatra basin. Currently, production is approximately 17,000 BOPD; most production comes from Formation Y, and a much smaller contribution comes from the shallower, but tighter, Formation X1 (reservoir characteristics are provided in the complete paper). A reservoir study for further field development of Formation X1 in Field X was conducted in 1999. On the basis of this study, it was determined that the recovery factor of Formation X1 was low (single-digit recovery). Given this low recovery factor, several options were considered to develop the remaining reserves better. The implementation of hydraulic fracturing was evaluated as one of the options to increase the oil recovery of the reservoir. From 2006 to mid-2008, 21 fracturing jobs were performed to stimulate the X1 B sand; the jobs resulted in an average oil-production gain of 80 BOPD per well, and the overall success rate was 71%. Since that time, the operator has performed approximately 20 hydraulic fractures per year in Field X. Fracturing Challenges and Treatment Evolution One of the main challenges while fracturing in Field X, Formation X1, is achieving enough fracture half-length to increase the reservoir contact. As a typical low-permeability formation, its post-fracture productivity is driven by the effective fracture length created during the fracturing job. Post-treatment evaluations from several of the wells indicated that the lack of stress contrast between the target zone and the adjacent barriers has led to the creation of short fractures. The rod-shaped proppant increased the conductivity of the proppant pack, which led to a better post-treatment fracture cleanup. Having better and earlier fracture cleanup increases the effective fracture length, which is essential when fracturing low-permeability formations. Besides providing much higher conductivity than intermediate-strength proppants (ISPs), the packing of rod-shaped proppant causes the rods to mechanically interlock to form a well-consolidated proppant pack that limits the proppant-flowback tendency without need of chemical surface modification to foster adhesion.

Near-Surface Velocity Model To Enhance PSDM Seismic Imaging of Dukhan Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18293, “Near-Surface Velocity Model of Dukhan Field From Multiphysics Survey To Enhance PSDM Seismic Imaging,” by K. Setiyono, Qatar Petroleum; S. Gallo, C. Boulanger, F. Bruere, F. Moreau, and B. Rondeleux, CGG; and J. Snow, Qatar Petroleum, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed. Dukhan field affords an opportunity to assess alternative near-surface velocity-modeling work flows that specifically integrate microgravity (MGR) and vertical electrical sounding (VES). A pilot study of the Dukhan seismic data demonstrates that integration of MGR/VES into prestack depth migration (PSDM) improves the fidelity of seismic images and results in an improved depth match. The resultant MGR/VES PSDM pilot model improved the velocity model between the surface and top Simsima formation on the basis of visible impact on the deeper structure obtained from imaging and better fit between the seismic depth horizons and well measured depths. Introduction The Dukhan field (Fig. 1) along the southwest coast of Qatar is an elongated anticline that has significant hydrocarbon reservoirs in the Jurassic Arab and deeper formations. In 2007, Qatar Petroleum invested in a new full-field, land and shallow-water 3D-seismic survey of the area. Despite considerable and continuous progress in seismic technology, obtaining an accurate, quantitative, well-focused seismic depth image at reservoir level remains challenging. In land seismic, a poor characterization of the near-surface geology is detrimental to the depth imaging of underlying structures. The proper knowledge of the near surface to correct for its perturbations onto the seismic wavefield remains one of the main challenges to be addressed. The near surface influences the kinematics as well as the dynamics of the source-generated seismic waves. Knowledge of the near surface to correct for its induced distortions is critical for a reliable use of seismic images, structures, and amplitude at reservoir level. The near-surface lateral and vertical velocity variations often are not accessible with seismic methods, even to the seismic refraction survey, because their depth of investigation is limited to the top of the shallowest hard layer. In addition, rapid lateral changes and large velocity contrasts are unfavorable to seismic refraction.

A Nonisothermal Wellbore Model and Its Application in Well Testing

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18152, “A Nonisothermal Wellbore Model With Complex Structure and Its Application in Well Testing,” by Shiyi Zheng, SPE, London South Bank University, and Yiqun Zhang, SPE, Heriot-Watt University, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. Although the wellbore is in a nonisothermal environment, heat transfer between the fluid in the wellbore and the formation is often ignored and temperature is usually assumed constant in data interpretation, which will lead to misunderstanding of the pressure profile. In this work, wavelet transform and a nonlinear-regression-analysis method were used to study the relationships between downhole temperature, pressure, and flow rate. A nonisothermal wellbore model was established that is capable of predicting temperature, pressure, flow rate, and liquid-fraction profiles under multirate and multiphase production scenarios. Introduction In order to monitor the downhole production and injection conditions, as well as make decisions for well-performance optimization, the dynamic temperature data acquired from permanent downhole gauges (PDGs) and distributed-temperature sensors (DTSs) are often interpreted widely. In this paper, first, the relationships among bottomhole-pressure (BHP), -temperature (BHT), and flow-rate data were analyzed briefly by use of wavelet transform and nonlinear regression. Next, a nonisothermal wellbore model with complex structure was derived theoretically step by step. Then, the wellbore model was coupled with an existing reservoir model through BHT. After that, several synthetic cases were simulated to verify the wellbore model. Finally, on the basis of the coupled wellbore/ reservoir model, the transient temperature behavior during flowing and shut-down periods was drawn out for well-testing analysis and some typical thermodynamic parameters were estimated by use of a set of field data. BHT, BHP, and Flow-Rate Relationships It is worth noting that formation pressure and temperature emerged in many similar characteristics. First, temperature and pressure meet the same diffusion equation. Second, at the junction between formation and well, near-wellbore damage should be considered for pressure. At the same time, on the temperature side, heat loss should also be considered, located in the formation, casing, tubing, and cement. Third, wellbore storage is compared with heat-capacity coefficient in wells. Fourth, constant-pressure and impermeable boundaries have been set for pressure boundaries, but the temperature boundary is always regarded as infinite ground. Analyses of the measured PDG data show that the temperature can also be used to provide reservoir information.

IPTC Doha — A successful event despite challenging times

The ninth edition of the International Petroleum Technology Conference (IPTC) took place 6–9 December 2015 in the Qatar National Convention Centre in Doha. This was the fourth time that Qatar Petroleum (QP) has hosted the event since the IPTC's inception in the same city back in 2005, with Shell acting as cohost for this year's event. Despite the current downturn in the oil markets, the conference and exhibition attracted 3,800 industry professionals, representing 630 companies from 63 countries.

Complex Reservoir Architecture Validated by Integrating Well-Testing Outcomes

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 17986, “Complex Reservoir Architecture Validated by Integrating Well-Testing Outcomes,” by Eleonora Azzarone, SPE, Enzo Beretta, SPE, Sergio Salvadori, and Pietro Bettazzoli, Eni, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. This work presents a real field example in which the integration of well-testing and geological interpretations increased the understanding of a complex, heterogeneous reservoir. An integrated study of both dynamic well-testing data and geological/seismic models was conducted to assess a very complex pressure response obtained from a production test conducted in an offshore oil well. The well-testing objectives were to improve reservoir characterization and to quantify the well productivity in a high-permeability oil-bearing sandstone formation. Introduction The target of the production test [drillstem test (DST)] is considered one of the more important reservoirs for the development of a field asset located in ultradeep water. Both the dimensions involved and the average petrophysical properties are expected to sustain quite good production performance. A dedicated test giving good and reliable interpreted results was considered essential to assess the expectations concerning the reservoir productivity and extent, thus confirming the viability of the development project. The DST addressed the general main well-testing objectives: the acquisition of representative reservoir-fluid samples (at surface and downhole); the estimation of formation pressure and temperature, average permeability, and well damage; the assessment of well productivity; and the detection of late-time effects (i.e., any presence of heterogeneities or permeability barriers within the radius investigated by the test with respect to the current geological/ seismic environment). The bottomhole data were acquired by a real-time acquisition system throughout the well testing to achieve an effective balance between the value of information and the optimization of the rig time and costs. The bottomhole-pressure (BHP) and -temperature data were transmitted in acoustic wireless mode through the tubing because no cables are allowed in ultradeep water, for safety reasons.

Production-Logging Tools Facilitate Well Testing in Challenging Environments

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 17771, “Well Testing in Challenging Environments: A Case Study From Onshore China,” by Xin Ling Peng, Mei Sheng Liang, Jie Hu, Xiao Lei Wu, and Dong Lin Qin, Sinopec, and Prasanna Tellapaneni, Bo Nan Ren, Tao Zhang, and Zhi Hong Guo, Schlumberger, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. The Pugang gas field, one of the biggest inland gas discoveries of the last decade in China, has hydrogen sulfide (H2S) concentrations as high as 10%, making surface- and downhole-facilities design and execution challenging. Testing these wells also is difficult because of the surface risks inherent in conventional testing. Well testing using production-logging tools recently has been introduced in this field and has been of tremendous benefit to the operator in identifying the inflow zones and in performing welltest analysis. Field Introduction The Pugang gas field, discovered in 2002, is the second-largest gas field in China and the largest sour field discovered in the last decade. This field is north of Chongqing in the Sichuan basin. The reservoir fluid in this field is dry gas with high H2S (14.4%) and carbon dioxide (CO2) content (9.91%). The field is flanked on the west with a gas/water contact at 5140-m true vertical depth subsea. With no voidage-replacement mechanism in place yet, the production of water because of the contact movement is also a concern for the operator. Therefore, production logging as a reservoir-monitoring and -surveillance tool has been used since 2010, and more than 18 wells have been tested to date. Gas in the Pugang field is mainly contained in the Lower Triassic Feixianguan and Upper Permian Changxing formations. These carbonates are open-platform carbonates, mainly platformmargin shoal and reef sediments. The Feixianguan formation is composed mainly of carbonate platform- margin shoal and evaporitic environments. The main porosity types in the Feixianguan formation include intercrystalline, solution-enlarged intercrystalline, solution vugs, and compressional microfractures. Normally, the solution porosity is connected by fractures, which gives rise to the high permeability observed in this formation.

An Integrated Methodology To Locate Oil Opportunities in Mature Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18004, “An Integrated Methodology To Locate the Remaining-Oil Opportunities in Mature Reservoirs in Offshore Sarawak, Malaysia,” by M.J. Zulhaimi, W.M.S. Wan Ibrahim, S. Sanyal, K.A. Zamri, M.N. Mohamad, and K.N.M. Zaini, EORC; R.D. Tewari, Petronas; and A.K. Pradhan, ADCO, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. A matured field is currently producing with greater than 85% water cut (WC) and has significant levels of uncertainty with respect to oil/water contact (OWC), flank structure, depth of spill points, production allocation, and residual oil saturation. A robust work flow was developed to identify infill opportunities by integrating material-balance study, cased-hole-log information, water diagnostic plots, decline-curve analysis, and other information. The comprehensive locate-the-remaining-oil (LTRO) methodologies applied have been successful and have helped to estimate the potential reserves as well. Introduction The field is 20 km offshore Sarawak, Malaysia, in water depths of 100 ft. The field structure consists of a 30,000×9,000-ft elongated anticline running northeast/southwest and comprises a series of stacked reservoirs at a depth of 4,000 to 9,500 ft. The field is considered structurally simple, with a normal growth fault affecting only the deep reservoirs and no other faults visible on 2D seismic or in the wells. The field reservoirs were deposited during the Late Miocene in a lower coastal plain to the coastal environment. The depositional environment of this field is dominated by a sequence of shore-face deposits. Sands are loosely consolidated, fine- to very-fine-grained, and interbedded with layers of silts and clays. Porosity ranges from 14 to 26%, with a fieldwide mean of 20%. The permeabilities are on the order of 50 to 3,000 md. Net sand thicknesses are less than 30 ft, with most individual sands at approximately 10 ft. The reservoirs are subdivided into three categories: Shallow reservoirs at depths of 4,000 to 5,300 ft are characterized by large gas caps and mostly thin oil rims and are currently considered unfaulted. Main reservoirs at depths of 5,300 to 6,000 ft with no gas caps are also currently considered unfaulted. Deep reservoirs at depths of 6,000 to 9,500 ft can carry high pressures and are dissected by a northwestheaded growth fault with possible associated additional faulting.

Long memory and fractional cointegration relationship between physical and financial oil markets

This paper investigates the relationship between spot-future oil volatility by examining the empirical evidence for the aspect followed by two process volatility. The analysis is undertaken using daily from January 2007 to March 2012 at the New York Mercantile Exchange (NYMEX) and International Petroleum Exchange (IPE). There is as yet little consensus on the methodology to test the fractional cointegration in crude oil markets. We consider semi-parametric frequency domain analysis of fractional cointegration between long memory processes. The estimation of predictive regression narrow band least square (NBLS) is based on the Fourier frequency number included in the spectral regression. Consistent with exploration the Geweke and Porter-Hudak (GPH) and local Whittle estimators, the results notice the non-stationary long memory in spot-future oil volatility and the mean reverting behaviour. An application to NBLS model, we indicate that futures oil volatilities are a consistent estimate of spots oil volatilities. The contribution of this paper is to demonstrate that oil futures prices display long memory and that form of long memory is persistence over the study period of 2007-2012 and proves the inter-relationship between financial and physical oil markets.

Method of Surface Interception To Access Annulus With Abnormal Gas Pressure

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18122, “A Safe and Efficient Method of Surface Interception To Access Outermost Sealed Annulus Charged With Abnormal Gas Pressure Relieves Well- Integrity Concerns,” by Prashun Kumar Das and Wael Moneer El-Mandrawy, Qatargas, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. One of the operator’s newly acquired ventures is in the North field offshore Qatar. Abnormal rise in Annuli C and D pressures during the last phase of drilling highlighted the need to investigate the condition of producing wells on other platforms. The chances of inner annuli becoming charged with shallow-gas pressure and possible communication to Annulus D was thought to be a well-integrity concern. Establishing safe access to the sealed and potentially gas-charged Annulus D thus posed a challenge. Introduction The North field is offshore northeast of Qatar and is the world’s largest nonassociated-gas field. The wells are typically 7-in. monobore completed with a 26-in. conductor and three casing strings. Wells are completed with a liner-top isolation packer, tied back to the surface with 7-in. corrosion-resistant-alloy tubing. The annuli between the well casings are labeled A (7×10¾ in.), B (10¾×13? in.), C (13?×18? in.), and D (18?×26 in.). Provisions were made for monitoring and bleeding off pressures in Annuli A, B, and C. Background During the drilling and well-completion phase, some of the wells developed unusual pressures in Annulus C. Attempts were made to bleed off gas through the drilling facility. However, pressures built up every time, indicating a continuous intrusion of gas. Further pressure bleedoff was not attempted because of concerns that it may open up the communication channels and aggravate the situation. Several attempts were then made to lubricate and fill Annulus C with treated brine, but these attempts did not help to subdue the gas pressure. A proposal was then made to operate the wells with modified maximum-allowable-annulus- surface-pressure and maximum-allowable- wellhead-operating-pressure techniques for Annulus C, considering it fully charged with gas. With time, it was established that the same wells also developed gas pressure in Annulus D.

Simulation of Residual Oil Saturation Through Tuning of Equilibrium Constants

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171806, “Simulation of Residual Oil Saturation in Near-Miscible Gasflooding Through Saturation-Dependent Tuning of the Equilibrium Constants,” by Leonardo Patacchini, Sébastien Duchenne, Marcel Bourgeois, Arthur Moncorgé, and Quentin Pallotta, Total, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. Conventional miscible- or near-miscible-gasflood simulation often overestimates oil recovery, mostly because it does not capture a series of physical effects tending to limit interphase compositional exchanges. The authors present a new engineering solution to this problem in the near-miscible case. The principle is, while using a black-oil or an equation-of-state description, to dynamically decrease the K-value of heavy components and possibly increase the K-value of light components as the oil saturation reaches the desired residual limit. Introduction The novel approach covered in this paper relies on an in-house research reservoir simulator (IHRRS). The starting point of this work is the model activated through the VAPPARS keyword in Eclipse 100 (black-oil code) that is extended to compositional simulation. The benefits of the proposed method are demonstrated on a reservoir-condition tertiary gas- injection experiment, performed in laboratories, for which residual saturations are easily and successfully history matched, along with oil-phase and individual-component production rate. Thermodynamic Equilibrium in IHRRS and Saturation- Dependent Tuning of the Equilibrium Constant (SDTEC) IHRRS is a research reservoir simulator designed to treat a general number of phases where each phase can hold an arbitrary number of components. Equations important to the use of IHRRS are described in detail in the complete paper. Also, detailed discussions of the use of the SDTEC method in black-oil and compositional simulation are presented in the complete paper.

Comments: Trying to Get in Balance

Editor's column All signs point to another bleak year for the oil and gas industry. Major operators have begun announcing significant capital spending cuts, and analysts see no quick fix to the current global supply/demand imbalance. ConocoPhillips’ and Chevron’s announcements last month of deep cuts in 2016 capital spending were likely the first in what is expected to be a wave of further reductions by operators in the wake of the lowest oil prices in a decade. Chevron plans to slash its budget 24% to USD 27 billion, with the most spending on international exploration and production projects and the second-largest amount going to US projects, including shale development in Texas. ConocoPhillips said it will spend USD 7.7 billion this year, a 25% decline from the reduced levels it spent in 2015. Other major operators echoed those sentiments that this year may be even more difficult than 2015. The outlook for 2016 was on the minds of many executives at last month’s International Petroleum Technology Conference in Doha. Global oil supply is still increasing faster than demand despite the plunge in oil prices and it will take a while to reverse that trend, Total Chief Executive Officer (CEO) Patrick Pouyanné told reporters at the conference, which is organized by SPE and other industry associations. “The market is oversupplied and production capacity will continue to grow because a lot of projects were sanctioned in 2013 and 2014. Many of those projects will be coming on line this year and in 2017,” he said. “(Total) does not expect a price recovery in 2016.” Oil production from the US Gulf of Mexico is currently rising, as many megaprojects invested in several years ago are now coming on line. Output from the Gulf of Mexico is about 19% higher now than it was a year ago, according to the US Energy Information Administration. ConocoPhillips’ Ryan Lance CEO said at the conference that US production is now running at about 9.1 million B/D, down from 9.6 million B/D in the first half of last year. US output will likely decline another 500,000 B/D this year, he said. That may not be enough, depending on the amount of oil Iran produces this year and with the world oversupply currently estimated at 2 million B/D. Iranian production could add anywhere from 500,000 B/D to 700,000 B/D to the market in 2016, according to a recent estimate from Barclays. Saudi Aramco’s CEO had a more positive view of the world oil market. Amin Nasser said he thought the market would begin to balance this year and that his company was continuing to invest in upstream projects to meet future world demand. Analysts Tudor, Pickering, Holt and Co. said that oil companies have canceled or delayed final investment decisions on about 150 projects in the past year that would have produced 125 billion bbl of oil equivalent. That could leave the world oil-short a few years from now if global demand continues to rise as expected. JPT

Deployment of a Remote Acoustic Monitoring System for Pipeline-Asset Integrity

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171763, “Field Deployment of an Innovative Acoustic Monitoring System for Remote Real-Time Pipeline-Asset Integrity,” by R. Schiavon, Tecnomare; G. Bernasconi, Politecnico di Milano; G. Giunta and G.P. Borghi, Eni; and N. Okere, NAOC, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. Since 2007, an operator in Nigeria has registered a significant increase of oil-spill events caused by sabotage and oil-theft activities. The risks for personnel safety and environmental protection were such that it was decided to investigate new detection and monitoring systems. The technology presented here allows detecting and locating leaks taking place at a distance from the sensor of up to 35 km. Introduction The technology of this system is based upon discrete vibroacoustic sensing. This technology takes advantage of the fact that any acoustic signal reaching, or generated upon, the pipeline will introduce vibroacoustic waves within the pipeline body and the transported-fluid medium (crude oil, brine, and natural gas). In addition to the general noise of the fluid flow within the pipeline, these acoustic waves are transported along the conduit for long distances. Especially within the fluid, the sound propagation is expected to travel several kilometers, depending on the density of the medium and the pipe diameter. In the pipe body, because of the variability of the boundary conditions, the calculation of the sound propagation is complex, but mathematical analyses proved the existence of modal solutions that are allowed to travel several kilometers. Moreover, for high- density fluids (i.e., crude oil or brine), the acoustic waves can be measured across the pipe shell. Vibroacoustic monitoring implies the recording of the low-frequency elastic waves traveling along the pipe body by use of accelerometers and geophones, and of the pressure wave traveling into the fluid by use of hydrophones. When the sensors are placed on both sides of a source point, cross-correlation techniques enable the localization of the origin point. If only one recording point is available, it is possible to take advantage of the different propagation velocity of the acoustic waves in the pipe shell and in the inner fluid.

Rotation by Reciprocation Casing-Landing Technology

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 172144, “Rotation by Reciprocation Casing-Landing Technology,” by R. Gosselin and T. Montgomery, Longhorn Casing Tools; A. Muriby, SPE, and Moataz Yussef, Wildcat Oilfield Services; and S. Karrani and A. Khamis, Abu Dhabi Marine Operating Company, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. With the innovation of extended-reach and directional drilling, running casing and liner strings has become increasingly difficult. Not much has been done to address the challenges, which include ledges and obstructions, washouts, swelling shale, bridging, high doglegs, difficult well profiles, fill on bottom, and well collapse. To overcome the challenges, a new product line was developed as a way to facilitate casing operations, especially for long horizontal strings, production strings, and intermediate casing strings. Introduction The technology can rotate independently from the casing when encountering obstructions and hanging. The rotation is performed by reciprocating the casing through 3- to 5-ft strokes that cause the tool shoe to act as a bit and ream. It drills off the obstruction and guides the casing string through ledges, tight swollen sections, and doglegs, allowing effective removal of fill and debris from below the casing/liner shoe to land at the intended total depth (TD). The technology comprises two main components: the tool body, which is made similar to the casing grade being run, and the internal mechanism, which is made from industrial-grade aluminum alloy for the mandrels and bronze components for the bit, both of which lend strength and durability to the tool while facilitating a smooth clean drillout with a standard polycrystalline-diamond-compact (PDC) bit. Technology Concept The tool provides rotation at the end of the casing string by reciprocating the casing string rather than by rotating the string at surface. It uses a very small amount of hydraulic pressure, provided by the mud pump, to enable the removal of fill by penetrating through it and circulating it out. Also, it provides deflection of the casing shoe to bypass ledges. The tool has a fixed helical mandrel connecting to the casing string, so the lower tool body is able to rotate. Only 21 psi of internal hydraulic pressure is needed to extend the lower tool body along the mandrel into an open position. By applying this pressure, the mechanism at the lower assembly of the tool rotates and extends into an open position. By setting weight on the tool, the lower assembly moves up along the mandrel, causing right-hand rotation on the lower assembly by lowering the casing string. The tool is effectively torque neutral, causing no torsional torque transmitted up the casing string.

ICD Well History and Future Use in a Giant Oil Field Offshore Abu Dhabi

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171836, “ICD Well History and Future Use in Giant Offshore Field, Abu Dhabi,” by Graham Edmonstone, Curtis Kofoed, Alfred Jackson, Shardul Parihar, Adriana Alvarez, Saad Mumtaz, and Ghassan Abdouche, Zakum Development Company, and Chris Shuchart, Christian Mayer, and Andrey Troshko, ExxonMobil, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. As part of a project that involves the use of four artificial islands to drill and complete more than 300 extended-reach-drilling (ERD) wells in a giant offshore oil field, several completion designs have been piloted for brownfield development. One well design incorporated the use of inflow-control devices (ICDs) and swell packers, which was the operator’s first use of such technology in a production well. The technology was installed in the pilot well to test inflow control and to manage future water production. Introduction The giant 1200-km2 offshore oil field is located 84 km northwest off Abu Dhabi Island and consists of a layered carbonate formation that was discovered in 1963. It has still only produced a small percentage of original oil in place, with water cut (WC) less than 15%. There have been almost 500 wells drilled in the field since field discovery. Development was based on pattern producer/injector wells, with each well using a dry tree on a wellhead platform tower. To achieve the strategic goal of increasing the production rate by approximately 40% and maintaining a plateau for up to 25 years, a brownfield development plan (UZ-750) has been generated that will use four artificial islands (Fig. 1) with large 3,000-hp land drilling rigs. The aforementioned island arrangement will allow the drilling of approximately 360 wells that will use ERD to drill horizontal laterals approximately 10,000 ft in length at measured depths up to 35,000 ft. The brownfield development plan calls for a parallel line drive for producer/injector-well pairs, to provide optimum sweep of the reservoir. The well-completion type is determined by geologically defined areas, which are differentiated by High- and low-permeability regions Faulted and fractured regions Transition regions Current (predicted) oil-water-saturation profiles The well-design process takes these into account along with sector modeling to determine well-completion design for the life of the well. Typically, wells in the crest of the field will have an ICD liner, in the near west of the field will have a predrilled liner, and in the west/ far northwest of the field will have a stimulation liner.

Prediction of Critical Gas Velocity of Liquid Unloading for Entire Well Deviation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17846, “Prediction of Critical Gas Velocity of Liquid Unloading for Entire Well Deviation,” by J. Li, Trican Well Service, and F. Almudairis and H. Zhang, The University of Tulsa, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. Liquid loading is a common production problem in mature gas wells. Correct prediction of the critical gas velocity at which the well starts to load is very important to the operators because it may allow them to take appropriate measures to prevent liquid loading and extend well production life. In this paper, a database related to the critical gas velocity is compiled with data from published literature. A new model is developed and evaluated with the experimental data. Introduction Gas wells often produce water and other condensate. In the early production stage, the gas-flow rate is high enough to carry the produced liquids to the surface. As the reservoir pressure is depleted, the produced-gas-flow rate decreases until the gas reaches a critical condition, at which time liquid loading is initiated. At the inception of liquid loading, the gas-flow rate is not sufficient to carry the liquid completely to the surface and the liquids start to accumulate at the bottom of the well. A backpressure then builds up, and the increased reservoir pressure will eventually be sufficient to lift the liquid to the surface. Once the liquid slug is pushed out by the gas, the liquid starts to reload the well again and the cycles are repeated until the well is eventually loaded completely and gas production stops. The most common liquid-loading symptoms observed in the field are pressure (or pressure-gradient) fluctuations and reduction of gas production. In general, there are two different liquid-loading principles proposed in the literature: liquid-droplet fallback and liquid-film reversal. The complete paper contains a literature review that follows the development of these principles. Data Compilation Liquid-loading-initiation mechanisms have been investigated in 3-in.-innerdiameter pipes with deviations of 0, 15, 30, and 45° from vertical. Others have used the same flow loop to study the liquid loading at deviations of 60, 70, 80, 85, and 88° from vertical. The superficial gas velocity ranged between 2 and 40 m/s, and the superficial liquid velocity varied from 0.01 to 0.1 m/s. Approximately 450 tests were performed. Pressure gradient, liquid holdup, and liquid-film thickness at the bottom of the tubing were also measured. Highspeed video cameras were used to observe flow pattern and film reversal. Complete film-reversal transition was applied to determine the critical gas velocity for the liquid-loading initiation. In the vertical case, the liquid film around the pipe periphery is almost uniform, and in the deviated case, it is nonuniform. In the latter, there is more liquid accumulated at the bottom of the pipe than at the top. This difference in liquid-film distribution around the pipe yields a difference in flow-pattern transitions and film reversal.

Smart Horizontal Wells for Development of Thin-Oil-Rim Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17753, “Smart-Horizontal-Well Drilling and Completion for Effective Development of Thin-Oil-Rim Reservoirs in Malaysia,” by Keng Seng Chan, Rahim Masoudi, Hooman Karkooti, Ridzuan Shaedin, and Mohamad B. Othman, Petronas, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. For thin-oil-rim reservoirs, well placement, well type, well path, and the completion methods must be evaluated with close integration of key reservoir and production-engineering considerations. This involves maximizing reservoir-fluid contact and drainage, optimizing well productivity, and optimizing the well life-cycle production profile along the wellbore. Field-implementation cases in Malaysia have shown that this integrated approach can significantly minimize the well count, enhance the well performance, and improve the ultimate recovery per well in thin-oil-rim reservoirs with varying reservoir complexity and uncertainties. Introduction Development of oil-rim reservoirs in Malaysia has been improved progressively in recent years through a series of reservoir-engineering studies and successful field implementations. Although typical oil-rim reservoirs are characteristically wedged between a gas cap and an underlying aquifer, they can be structurally very complicated, with faults and flow boundaries having varying dips and saddles. Oil-rim reservoirs of various sand thickness can also be stacked and compartmentalized. Aquifer support varies from sector to sector, resulting in uneven pressure depletion and fluid-contact change. Wells are completed with multiple strings to produce separately from various different stacked sands with significantly large pressure difference. Well life can be short producing at high watercut and high gas/oil ratio (GOR) because of wells having partial penetration operated at high pressure drawdown. For such a well-development strategy, idle-well rate increases dramatically. Currently, active wells in some key oil-rim reservoirs number far less than 50%. Field oil recovery remains low even after 25 years of continuous production. Force Balance in Thin-Oil-Rim Reservoirs There are several drive mechanisms dominant in oil-rim reservoirs—namely, gas-cap and aquifer expansion, viscous and gravity balance, and solution-gas-expansion drive. Produced-gas reinjection; controlled pressure drawdown at wells in different reservoir sectors on the basis of varying aquifer strength and sand-layer dip angle; and the placement, spacing, and completion of the wells could all affect the balance of these drives. The art of this balance is to keep the oil rim in place, avoiding dramatic migration of the oil rim by having a good vertical displacement conformance.

IPTC 2015 Doha: Delivering a strong, balanced geosciences and engineering technical program

Practically speaking, the 2015 International Petroleum Technology Conference (IPTC) is just around the corner, 6–9 December 2015 in Doha, Qatar ( www.iptcnet.org/2015/doha ). The annual IPTC conference, which rotates between the Middle East and Asia Pacific, has evolved into one of the premier technically oriented multidisciplinary conferences in the region. Four professional societies (American Association of Petroleum Geologists [AAPG], European Association of Geoscientists and Engineers [EAGE], Society of Exploration Geophysicists [SEG], and Society of Petroleum Engineers [SPE]) work alongside industry host and cohost organizations to develop the conference. Host and cohost organizations for IPTC 2015 Doha, which is the Ninth IPTC conference, are Qatar Petroleum and Shell. The theme for this year's conference is “Technology and Partnerships for a Sustainable Energy Future.”

Acoustic Measurements Aid Mechanical-Damage Characterization in Proppant Packs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18092, “Mechanical-Damage Characterization in Proppant Packs Using Acoustic Measurements,” by Aderonke Aderibigbe, SPE, Clotilde Chen Valdes, and Zoya Heidari, SPE, Texas A&M University, and Tihana Fuss, Saint-Gobain Proppants, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. The strength and conductivity of proppant packs are key parameters for assessing their performance. Mechanical damage of proppants usually is analyzed by crush tests. However, measurements from these tests remain questionable because of discrepancies in procedures and test results. This paper introduces a new technique based on interpretation of acoustic measurements to quantify mechanical damage in propping agents. Introduction Mechanical damage that leads to compaction and crushing is studied for sands by measuring ultrasonic velocities. Elastic properties can be estimated from compressional- and shear-wave velocities calculated from acoustic measurements. The elastic properties of unconsolidated sands usually are studied by use of effective-medium models for granular media. Effective- medium-theory approaches such as the Hertz- Mindlin model are often used to derive the effective elastic moduli of packings of identical and spherical granular materials. This model combines the Hertzian contact model, which is used to estimate the normal (compressional) stiffness for two identical spheres, and the Mindlin contact model, which is used to estimate the tangential (shear) stiffness of the spheres. Work investigating the relationship between the ratio of compressional- to shear-wave velocities and pressure as a result of preconsolidation and sorting in unconsolidated sands showed that the Hertz-Mindlin model overestimated the shear moduli and underestimated the pressure dependence of the moduli and the velocities of the unconsolidated sands when compared with experimental data from ultrasonic measurements. The discrepancy was attributed to the inability of the model to account for rotation of grains and slip at their boundaries. The work applied a modified Hertz-Mindlin model, in which it is assumed that there is no friction between the grains (hence, the tangential stiffness is negligible), to obtain a reasonable match between the model and experimental results. The disparities were attributed to the angularity of the sand grains and the assumption of no slip at the grain contacts. The disparities were modified by introducing an average- angularity parameter and assuming slip at the grain contacts. Previous publications documented applications of effective-medium models for assessment of elastic properties in rocks and unconsolidated sands. However, effective-medium models have not been applied in the assessment of elastic properties of proppant packs.

Optimizing Spacing of Multistage-Fractured Horizontal Wells in Gas Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171688, “Optimizing Spacing of Horizontal, Multistage-Fractured Wells in Gas Reservoirs,” by Maryam Alghannam and Zillur Rahim, Saudi Aramco, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. The growing demand for gas in Saudi Arabia and the availability of multistage-fracturing (MSF) horizontal-well technology have spurred the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently by use of MSF strongly depends on well spacing, especially for low-permeability reservoirs. This paper gives the recommended MSF horizontal-well spacing for several development scenarios in Saudi Arabian gas-reservoir environments. Theoretical Background There are four different flow regimes for multiple-fracture systems without wellbore storage: early linear, early radial, formation linear, and pseudoradial flow (Fig. 1). The initial flow period observed is the linear flow, where fluid flow toward the fractures in the formation is perpendicular to the fracture planes. This flow exists when each fracture behaves independently and most of the fluid entering the wellbore comes from the fractures (when the fracture-tip effects have not yet affected the pressure behavior). After the start of the flow into the fracture tips, the early radial flow develops while there is still no communication between fractures. This flow regime may occur briefly or it may not occur at all, depending on the fracture length and spacing. Subsequently, formation linear flow develops after the fracture interference has been felt and the flow becomes normal to the horizontal well. Finally, the pseudoradial-flow regime develops in the formation, where the flow appears radial toward the entire well/fracture system. During this flow period, the composite fracture system behaves as if it were a single fracture. The flow eventually will reach pseudosteady state when it hits the reservoir boundaries or interferes with surrounding wells. The rate at which the flow regime develops, from the start of production under transient conditions until it reaches reservoir depletion under pseudosteady state, is highly dependent on well spacing and well and reservoir characteristics.