This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202265, “Leap of Faith From Conventional to EM Look-Ahead: A Game-Changing Technology To Improve Well Efficiency,” by Muhamad Yanuar Mahardi, Hendarsyah Hendarsyah, and Kharisma Endarmoyo, PT Pertamina, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The structure in the Matindok block in Central Sulawesi operated by Pertamina has proven producible gas reserves in the Minahaki formation. One of the main challenges in this area is the low resolution of seismic data, leading to a high depth uncertainty. The complete paper describes a technology developed to meet these challenges with the capability to map and detect lithology changes ahead of the bit in real time. Geological Background A first exploration well, PEP-001, was drilled in 2018. The structure has a Miocene carbonate buildup play, and the target reservoir is the M pinnacle carbonate reef. The PEP-001 well was planned to set the 9⅝-in. casing point above the top of the M formation. Offset wells did not show any clear markers in the thick shale above the M formation that could have been used for log correlation. In previously drilled offset wells, correlation was performed convention-ally by examination of cutting samples and on drilling breaks. However, when Well PEP-001 was drilled, no apparent drilling break was observed. By the time cuttings reached the surface, the bit had drilled into 20 m of the M formation. Because the casing covered most of the upper carbonate formation, openhole logging and well-testing data were not acquired to delineate the target formation optimally. The second exploration well, PEP-002, was planned with an objective of setting 9⅝-in. casing approximately 5 m above the top of M to acquire full-interval coverage of coring, openhole wireline logging, and well testing. This information was critical for optimal reservoir delineation to allow for accurate reserves calculation and future development. Conventional correlation methods have proven insufficient for casing point placement. The presence of limestone stringers in offset wells within proximity of the top of M presented an additional challenge. The stringers could have been misinterpreted as the main carbonate body, if interpretation were based solely on cutting samples. Real-Time Electromagnetic (EM) Look-Ahead Technology

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202661, “Combination of Radial Drilling Technology With Acid Jetting: New Approach in Carbonate Reservoir Stimulation,” by Ayrat Bashirov, Ilya Lyagov, and Ilya Galas, Perfobur, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The complete paper describes an approach to stimulate carbonate formations with bedding water or a gas cap. The technique is a combination of acid jetting and a radial drilling technology that uses mechanical radial drilling with a slim mud motor. The primary advantages of the technology include controlled trajectory and the possibility of re-entry into channels. The novelty of the technology is in its ability to deploy acids in the rock far away from the wellbore through the mechanically drilled holes with known depths and azimuths. Reservoir Description The mature field is in central Russia in the Republic of Bashkortostan. The field contains both sandstone and carbonate reservoirs. Oil depth is from 780 to 1830 m. Six reservoirs are in development. This study concentrates on projects in a carbonate formation that is a substage of the early Pennsylvanian Period. This formation is highly heterogeneous with closely underlying water. Permeability of the reservoir is approximately 43 md; reservoir pressure is 1,000 psi, and oil density is 0.891 g/cm 3 . Two adjacent well candidates with identical reservoir properties were selected for the study, with a distance between wells of approximately 136 m. Net oil thickness in Well A is 4.4 m and 3 m in Well B. Mechanical Radial Drilling Technology The technology described by the authors uses mechanical radial drilling with a slim mud motor. The technology allows the drilling of a network of radial channels up to 15 m long with up to four channels of different trajectories on one level. The technical system features a modular construction for ease of assembly at the wellhead area and increased operational efficiency. The main elements of the technical system include the following: - Pipe pusher connected at the top with an overflow valve module and, at the bottom, with a guiding device connected by means of a hydraulic pusher - Flexible pipe assembly with a small (nonstandard) sectional mud motor - Drilling bit (milling cutter for window cutting) - Special whipstock and an anchor module with an orienting funnel connected from below to the pipe frame

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199617, “Drilling Performance Evaluation Using Advanced BHA Modeling and Field Validation,” by Jeremy Greenwood, SPE, Julien Marck, SPE, and Vakkeyil Naveen Nair, Halliburton, et al., prepared for the 2020 IADC/SPE International Drilling Conference and Exhibition, Galveston, Texas, 3-5 March. The paper has not been peer reviewed. Implementing a physics-based digital twin of a drilling system can enable the drilling team to leverage data at each stage of the engineering process to deliver more-consistent, repeatable drilling performance and improved borehole quality, which in turn enables drilling farther and faster while increasing downhole tool life. The complete paper discusses a new performance-evaluation methodology that combines bottomhole assembly (BHA) modeling with field data. BHA modeling simulates the drilling process accurately to establish key performance indicators (KPIs) to help optimize BHA designs to deliver improvements in drilling performance and wellbore quality. The model also can estimate quantities such as microtortuosity that are not directly measured by standard equipment. Importance of Effective BHA Performance Evaluation Determining the cumulative effect of BHA behavior during drilling on the quality of the wellbore and the subsequent impact on performance and life of the BHA is an important goal for improving overall drilling and well-delivery efficiencies. A higher-quality wellbore not only has a positive effect on reducing the time required for all drilling, casing, or completions running operations; in curved holes, it can also extend the life of the drilling equipment by reducing the rate of accumulation of fatigue and reducing the amount of work the bit is required to perform. This leads to longer runs because the system is more mechanically efficient and has a reduced equipment failure rate. Developing an effective set of measurements allows for an objective comparison of different BHA designs and stabilization, bit selections, and downhole drive systems of rotary steerable tools, motors, or turbines. This quantification of BHA performance can be used to improve BHA designs in terms of component stiffness, amount and position of stabilization, type and configuration of the drive system, and bit-design features. Defining terms to describe borehole quality at different scales is necessary to develop indices that are comparable across wells and that reflect any deviation of the wellbore from a perfectly smooth path. To fully quantify the mechanical effect of wellbore quality on the BHA, a wellbore-propagation model was developed to replicate the borehole and determine the accumulated stresses as the BHA passes through it. This approach overcomes the limitations of not having the required resolution of downhole measurements that accurately describe the wellbore trajectory on the smaller scale. The validation of the propagation model has been completed on multiple runs with examples presented in the complete paper.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 193883, “Robust Multiobjective Field Development Optimization for the Mariner Asset,” by Remus Gabriel Hanea, SPE, Ole Petter Bjorlykke, Yastoor Hasmi, and Tao Feng, Equinor, and Rahul Mark Fonseca, TNO, prepared for the 2019 SPE Reservoir Simulation Conference, Galveston, Texas, USA, 10–11 April. The paper has not been peer reviewed. The growing popularity of model-based optimization work flows has resulted in an increase in their application to field cases. In the complete paper, the authors present the challenges, results, and learnings from a 2-year robust multiobjective optimization application at the Mariner heavy-oil asset in the UK sector of the North Sea. The authors used the efficient stochastic simplex approximate gradient technique (StoSAG) to achieve optimization incorporating geological and petrophysical uncertainty. Depending on the problems, significant increases of between 5 and 20% in the expected value of the objective function were achieved. For the multiobjective optimization cases, nontrivial optimal strategies reduced gas production by 40% with less than 1% loss in the economic objective. Introduction To date, most studies of single- and multiobjective optimization have focused on a single study with a specific purpose. Very few studies have used these work flows in an operational setting (i.e., during the field-development-planning stage at an asset tackling a variety of•problems). Including uncertainty is an important step in decision making during field-development planning, especially because uncertainty is so extensive at this stage in the life cycle of a field. Considering a range of potential development scenarios that will provide the necessary tools to enable robust decisions is imperative. These scenarios should also account for the fact that different objectives often conflict with one another. Thus, there is a need for multiobjective optimization under uncertainty, which can be applied in an operational setting. Adapting model-based optimization work flows requires computational efficiency. While the adjoint-based gradient method is computationally very efficient, it is not suitably flexible to incorporate different types of control variables and requires access to the simulation source code as well as a significant implementation effort. Thus, in this paper, the authors use the StoSAG technique. They chose to use an approximate gradient method for the optimization instead of a derivative-free technique because the computational costs for derivative-free methods are usually higher when uncertainty, in terms of different model realizations, is considered. StoSAG is an approximate-gradient-based approach that has proven practical for optimization under uncertainty. A user must decide on the ratio of geological model realizations to control perturbations. The authors used a ratio of 1:1 for all experiments unless otherwise specified, making the number of control perturbations equal to the number of geological realizations. This is computationally the most-efficient approach for large-scale optimization under uncertainty when using high-fidelity, full-physics-simulation models. The objective function is the usual expression for (simple) net present value as used in life-cycle-optimization studies.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191728, “Large-Scale Field Development Optimization Using High-Performance Parallel Simulation and Cloud Computing Technology,” by Shusei Tanaka, SPE, Zhenzhen Wang, SPE, Kaveh Dehghani, SPE, Jincong He, SPE, Baskar Velusamy, and Xian-Huan Wen, SPE, Chevron, prepared for the 2018 SPE Annual Technology Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Field-development optimization is challenging because of the large number of control parameters, model complexity, and subsurface uncertainties. The complete paper discusses a study in which the authors propose a joint field-development and well-control-optimization work flow using high-performance parallel simulation and commercial cloud computing, and demonstrate its application through an•offshore oilfield•development. Introduction Designing a field-development plan to maximize the profitability of the asset involves accounting for many factors. Commonly, a field-development plan follows a staged process in which several alternatives are appraised and the one with the best economics is selected. The selected plan is then optimized while considering schedule and cost. Earth modeling and reservoir simulation are often used to provide probabilistic ranges of oil in place or net recovery for a given design at each phase of the process. This requires effective cross-functional teamwork to achieve quality decisions by relying on knowledge and skills spanning different disciplines. Proposed Work Flow Closed-loop or real-time reservoir management are terms often used to describe field-development optimization. These involve rapid data assimilation to define or update subsurface uncertainties and follow optimization processes to find the optimal combination of control parameters. These processes are not single-step but are executed iteratively during reservoir life. The focus of this paper is to describe the optimization process for maximizing economical values by selecting the best development plan under given ranges of subsurface uncertainties. The work flow proposed by the authors controls topside facilities, the number of wells, their trajectories, the drilling sequence, and completion strategy simultaneously, while considering subsurface uncertainties and constraints. The authors use a next-generation reservoir simulator and commercial cloud computing to explore the possibility of achieving an optimized development scenario within reasonable time and cost constraints. The combination of high-performance simulators and virtually unlimited scalability in the cloud provides opportunities for joint field-development optimization without reducing the number of control parameters, enabling the developed work flow to be applicable to various asset-development scenarios. The proposed work flow was applied to the Olympus field case, which is an optimization benchmarking problem developed by the Netherlands Organization for Applied Scientific Research using a synthetic North Sea-type reservoir. The study objective was to improve the net present value (NPV) after 20 years of operation by controlling the number and location of platforms and the number of injectors and producers as well as their trajectories and drilling sequence. The large number of control parameters and subsurface uncertainties make the optimization process challenging. Three optimization techniques—genetic algorithm (GA), particle swarm optimization (PSO), and ensemble-based optimization (EnOpt)—were tested and their performances compared. Best results, in terms of NPV improvement, were obtained by using the mixed-integer genetic algorithm method.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190860, “Evaluating the Impact of Lateral Landing, Wellbore Trajectory, and Hydraulic Fractures To Determine Unconventional Reservoir Productivity,” by Piyush Pankaj, Priyavrat Shukla, SPE, Ge Yuan, and Xu Zhang, Schlumberger, prepared for the 2018 SPE Europec featured at the 80th EAGE Annual Conference and Exhibition, Copenhagen, Denmark, 11–14 June. The paper has not been peer reviewed. Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. This paper demonstrates the need to couple the wellbore model to the reservoir-simulation and hydraulic-fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity. The authors aim to demonstrate and deconvolute the well-trajectory plan with an integrated parametric study that helps to improve well productivity. Methodology To plan a well profile, two critical pieces of information are required: Lateral landing depth, and well trajectory originating from the landing depth. To reach the targeted landing depth, the well trajectory undergoes a certain buildup of curvature deviating from the vertical section and, eventually, when the landing depth is reached, the designed trajectory profile is maintained and continued for the horizontal wellbore. The authors evaluated well trajectory and well productivity on the basis of the effect of the following parameters to guide well-trajectory planning: Hydraulic-fracturing fluid Natural fracture network Wellbore trajectory, undulations, toe up, toe down, or combinations Production operations such as proppant flowback, fracturing choke management, and well shutdown Geological Review of the Model A 3D earth model in the Permian Basin for the Wolfcamp shale was used to develop a work flow for determining well landing and well trajectory. The Wolfcamp shale covers most of the Midland Basin and ranges in thickness from 200 ft in the north of the basin to 2,600 ft in the south. The entire play is dominated by a fine-grained, naturally fractured source rock. The depths range from 5,500 to 11,000 ft. The Wolfcamp is slightly overpressured, with the pressure gradient varying between 0.55 and 0.70 psi/ft. In the past few years, the Wolfcamp has become one of the most profitable and exploited unconventional plays in the US. Almost all of the operators are collecting a significant share of their well inventory, which yields over 1,000 BOPD routinely in initial-production rate. The production declines within a short period (6 to 9 months). The recovery factors remain in the single digits for most operators. The Wolfcamp, Spraberry, and Bone Spring formations are the most prolific in the basin. Defining Landing Depth The proposed solution considers applying an end-to-end cycle of a streamlined work flow that starts with sampling engineered landing location points in the geomodel defined by the user on the basis of reservoir-quality (RQ) cutoffs. The first step is building the geological model around the sweet spot. This geological model contains petrophysical and mechanical properties of the rock along the depth of the targeted interval.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28517, “Deepwater Extended-Reach-Well Planning Through Depleted Reservoirs,” by Beng-Hooi Shi, Jennifer Koh, Dexter Liew, and Guat-Lee Chio, Shell, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. Because of the depleted nature of all three reservoirs located above the untapped reservoir, a need exists to drill through these depleted intervals with an extremely narrow margin window (less than 0.5 lbm/gal). An added complexity is the location of the reservoir, directly below a hydrates bulge. To address the challenges of this well, an integrated approach between various disciplines has proved to be a critical success factor. Introduction The field is offshore Sabah. The first phase of the development was completed in 2014, with 16 wells drilled. The development includes gas reinjection and seawater injection. The hydrocarbons are trapped in a four-way dip closure developed in an anticline structure containing four sand reservoirs separated by sealing shale layers. The Phase 1 development targeted the two main reservoir units (B and C) in the middle of the four reservoir sands. The pressure maintenance for the development of these two main reservoir units is provided by a combination of downdip water injection in the water leg and crestal gas injection in the gas cap. The second phase, comprising two oil producers and two water injectors, aims to maintain the oil-production plateau. One of the Phase 2 objectives is to target the deepest untapped reservoir (D) in the field with Well 4. However, as mentioned previously, Well 4 must drill through depleted intervals with extremely narrow drilling margins. Two of the four wells (Wells 1 and 2) only will drill into the depleted B reservoir in the final reservoir hole section, while the third well will cross the depleted B reservoir before drilling into the depleted target reservoir, C, in the final hole section. Phase 2 will offer the opportunity to acquire further data. Because of the stacked arrangement of Reservoirs A, B, C, and D and the wells targeting different reservoirs, a possibility exists to sequence the drilling campaign in a batch mode and to use data acquisition, operational learnings, and prediction validation before committing to drilling the intermediate and reservoir sections of the most difficult well (Well 4). The projected formation pore pressure and fracture gradient (PPFG) poses significant drilling challenges because of depletion plus the geomechanical requirements. The Reservoir C water injector is predicted to have a limited drilling margin because of the depletion of Reservoir B.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187502, “Production Optimization in the Midland Basin Through Lateral Multiphase-Flow Simulation,” by Yogashri Pradhan, SPE, and Hongjie Xiong, SPE, Texas Oil and Gas Institute, prepared for the 2017 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 13–14 September. The paper has not been peer reviewed. Wellbore lateral lengths and uniformity are important for production optimization, affecting liquid holdup and productivity throughout well production life. However, wellbore construction designed for holding leases and completed under time constraints could negatively affect production and limit operators’ potential for their acreage. This paper demonstrates a work flow to determine optimal lateral lengths and trajectories in the Midland Basin by studying the effect of the lateral length and trajectory on well production. Introduction Operators often use a scalar to determine wellbore contributions for wells with an atypical lateral length on their leases. The work flow presented here provides realizations to justify use of this scalar, evaluating whether lateral lengths proportionally increase production, whether wellbore contributions are uniform throughout the lateral length of the wells, and whether various wellbore deviations and tortuosities should have the same scalar applied for estimating well production. A team investigated the effect of lateral length on well estimated ultimate recovery (EUR). The EURs were calculated from daily production data from 15 operators and then normalized by well lateral length from the top perforation to the bottom perforation. The modified hyperbolic method was used to perform the decline-curve analysis. Simply applying a scalar for the lateral length among the wells would not yield proportionate EURs. When drilled and completed in unconventional reservoirs with multiple-stage hydraulic fracturing, horizontal wells experience a decline in productivity with time because the conductivity of those manmade fractures deteriorates with production and time. Therefore, in order to understand the effect of wellbore trajectory and lateral length on production fully, the team developed a work flow to incorporate an in-depth analysis on transient effects of wellbore hydraulics combined with unconventional reservoir performance over time. Methodology To develop an understanding of reservoir performance over time, numerical models are developed on the basis of previous knowledge, geology, and reservoir data. With respect to the Lower Spraberry and Wolfcamp B wells considered in this study, case studies for which are presented in the complete paper, the numerical models were first calibrated with historical pressure and production data. Fig. 1 displays the work flow that the team developed to combine long-term reservoir performance with wellbore hydraulics. The team used several production metrics to compare wellbore contributions throughout the lateral affected by the trajectory with respect to different times throughout the well life, including drawdown pressure, pressure decline throughout the lateral, and liquid-holdup results.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188265, “Use of Data Analytics To Improve Well-Placement Optimization Under Uncertainty,” by Daniel Busby, SPE, Frédérik Pivot, and Amine Tadjer, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Well-placement optimization is one of the more challenging problems in the oil and gas industry. Although several optimization methods have been proposed, the most-used approach remains that of manual optimization by reservoir engineers. The work flow proposed here uses a machine-learning algorithm trained on simulated data to evaluate the performance of possible well locations and configurations. Introduction Extensive literature has been published about well-placement optimization; authors have proposed many different approaches (e.g., advanced optimization techniques, adjoint methods, experimental design, and streamline solutions). Real field experience, however, has shown that these techniques are rarely used. In practice, expert engineers usually identify the main factors affecting a future well’s production. They consider these factors in obtaining the best well configurations. These are then evaluated with a full-field reservoir-simulation model. Uncertainty is handled in the process typically in a second phase to test the robustness of the proposed development plan by running a few alternative models corresponding to some low and high cases and, more rarely, on a full Monte Carlo set of models generated by the full prior-model uncertainty. The reasons the different optimization methods proposed in the literature are not used in operations can vary: difficulty in handling all the operational constraints during optimization, a prohibitive number of simulation runs, relatively poor performance of the optimization methods when considering many complex production and injection wells, and the complexity of the method and its configuration. The approach proposed here is not a proper well-placement optimization method; it is more a set of data-analytics tools aimed at helping reservoir engineers to explore the extremely large domain of possible solutions and, it is hoped, to find better solutions. This paper’s objective is to provide a methodology and some guidelines that can be adapted to each specific field case. The idea is to follow the typical work flow used by reservoir engineers while adding data-analytics techniques to improve the decision-making process. Methodology This work presents a methodology to address the problem of field development planning mainly for greenfields, although a similar work flow can be applied to mature fields. The first step in field development planning is to perform a study to incorporate geological, seismic, and fluid data into a reservoir-simulation model.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184074, “Microdogleg Detection With Continuous Inclination Measurements and Advanced BHA Modeling,” by K.A. Mills, SPE, and S. Menand, SPE, DrillScan, and R. Suarez, SPE, Nabors, prepared for the 2016 SPE Eastern Regional Meeting, Canton, Ohio, USA, 13–15 September. The paper has not been peer reviewed. Microdoglegs are a natural effect of any vertical or directional well that can explain a wide variety of downhole problems. A trajectory-prediction model able to calculate the inclination and azimuth approximately every 12 in. has been developed to estimate microdoglegs using standard surveys, bottomhole-assembly (BHA) data, and steering parameters. This new methodology combining downhole data measurements with drillstring-modeling analysis highlights the potential for drilling optimization and wellbore placement. Wellbore Trajectory Standard Surveys. Surveys are generally taken at an interval of every 95 ft, the length of one stand. While the general recommendation is to decrease the survey interval when building faster than 3°/100 ft, this is often neglected because there is no advantage seen in wellbore-positioning-uncertainty models. The well path between each survey point typically is calculated using the minimum-curvature approach, which assumes a curve of equal angle along the surface of a sphere with only one radius in a 3D plane. Looking at the well as a whole, this approach appears logical and yields reasonable-looking trajectories; however, when examining more-frequent survey data, it becomes obvious how this method can mislead users to think that the well path is much smoother than it actually is. Continuous-survey measurements have enabled the industry to take a closer look at what is happening between survey points, in highlighting microdoglegs quite often undetected by standard surveys. Continuous Surveys. Doglegs are generally discussed on a well level. Wells are analyzed for tortuosity looking at the change in trajectory from one survey point to the next. Little thought is given to what changes happen between those points unless a dysfunction occurs. Aggressive directional work can lead to the creation of microdoglegs, or doglegs on a scale of a few feet. Quick changes in direction create microdoglegs, which can contribute overall to higher torque and drag. In examining continuous surveys, the actions of the directional driller can be seen clearly and doglegs can be examined more closely. While continuous-survey data have become more common in the industry, not all measurement-while-drilling (MWD) tools are equipped for the measurements and, generally, data must be processed at surface on the basis of the previous survey. In the absence of continuous-survey data, BHA modeling run on a step-by-step basis can aid in wellbore placement, failure analysis, and post-well evaluation.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181598, “Prospective Unlocking of Future Reserves in Offshore Abu Dhabi: Field-Life Extension Through Hybrid Development Concept,” by T. Nakashima, SPE, D. Ouzzane, SPE, G. Dudley, SPE, and M. Al-Marzouqi, ADMA-OPCO, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed. Field A, a giant field consisting of many subreservoirs, is offshore Abu Dhabi and has produced for 50 years, mainly through peripheral water injection. A long-term development plan (LDP) for the field aims to extend the production plateau by 25 years through infill drilling and waterfloods. This paper describes an approach for optimizing the number and type of drilling centers required to enable the development plan to be flexible in design to accommodate infrastructure, facilities, drilling, and subsurface constraints. Introduction Field A, a giant carbonate field, has been developed for 50 years. As the field reaches maturity, it moves to another phase of development. Design of the next development phase, the LDP, began in the early 2010s. The LDP assessment stage, which screened the surface and subsurface development concept, was recently completed, and the development planning team is preparing for the selection stage. The assessment-stage conclusion was for drilling from artificial islands (AIs), wellhead towers (WHTs), or a combination of both and leaves a degree of freedom. This paper describes the optimization approach of the drilling-center options. The LDP is just the first phase of a large-scale long-span offshore reservoir redevelopment that aims for a further 50 years of production. The complexity of the field is significant because of limited seabed space, the age of the existing surface facilities and pipelines, and challenging drilling circumstances. These complexities differentiate the development project from other offshore projects, and an appropriate selection of drilling centers is one of the more important keys to project success. Field and Development History The field of carbonate reservoirs is in shallow water. The field is 40×20 km, and different reservoirs have been developed by two different operators. The stack of reservoirs is divided into shallower reservoirs (U Reservoirs) and deeper reservoirs (L Reservoirs). The L Reservoirs are geologically divided into two major reservoirs, L1 and L2, which have been developed similarly. The development began with natural production with original reservoir energy. Beginning in the 1970s, pressure maintenance through dump flood-water injection by connecting the target reservoirs with a shallow aquifer was conducted for 10 years. For further reservoir-pressure maintenance, powered peripheral water injection was started, and the development scheme has been continuous, with reinforced pressure maintenance through immiscible gas injection from the top structure.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176120, “Success Story: A New Development Concept Utilizing New Advanced Technology in a Very Old Complex Mature Field,” by K.F. Ng, T. Afandi, D. Sa’adon, J. Ja’afar, M.A. Omar, and N.A. Latiff, Petronas, and G.I. Santoso, K. Alang, I.D. Roberts, N. Murad, D. Permanasari, and F. Kutty, Schlumberger, prepared for the 2015 SPE Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 20–22 October. The paper has not been peer reviewed. The T Field, located offshore east Malaysia, is a mature oil field that began its development in the 1970s. Conceptual geological models generally illustrated this field as a retrogradational turbidite setting. It is commonly known that the turbidite channel has enormous geological complexity and, therefore, presents great challenges for successful horizontal-well placement. This paper describes the first job in southeast Asia in developing horizontal-well placement in a turbidite environment. Introduction As of 15 years ago, T Field’s remaining oil deposits were present in the relatively thin turbidite channel complex on the steep-sloping flank of the field. Vertical and slanted wells were drilled to produce the targeted reserves, but post-drilling findings always showed inconsistency in sand existence and distribution because of lateral sand discontinuity. Because of the limited infill reservoirs, high reservoir dip angle, and less-prolific productivity, drilling a highly deviated oil producer along the reservoir dip and steering along its productive layer in the oil leg are found to be the optimal drilling approach. However, high well-placement risks were assessed owing to uncertainties in lateral sand distribution, variable formation dip, and fluid contacts. Evaluating Infill/Redevelopment Potential Some reservoirs located within the western area were believed to carry more re-serves; production data indicated that downdip oil remains untapped by existing producers. An average dipping angle of 13 to 20° and gas-cap-dominant drive suggested that remaining-oil potential could be unlocked only through the addition of the drainage point. Material-balance analysis was conducted, which further verified the earlier deduction by showing that the targeted reservoir contains more oil in place compared with existing book figures and has reserves at approximately twice the amount of previous estimates made from decline-curve analysis. A reservoir model was subsequently constructed. Two types of reservoir models were built in this exercise: a simple grid homogeneous model and a heterogeneous model that was created by referring to a geological depositional concept and to reservoir distribution based on a geostatistical method. Reservoir-modeling and -simulation results are consistent with those obtained from material balance. As expected, the secondary-recovery method will result in an incremental recovery because of the pressure maintenance and better sweep efficiency. However, this recovery is not ideal; the reservoir pressure was halved because of historical production, and lateral discontinuity still exists. Infill drilling was recommended as the best way forward. Well-Concept and -Execution Strategy The feasibility of executing the drilling campaign during the early stage of the study was also considered. In past development campaigns, deviated wells were drilled to penetrate and produce from multistacked reservoirs. The replication of such practices may result in missing the reservoir target because of the high potential of reservoir discontinuity.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176442, “New Multilayer Boundary-Detection Service Employed in Complex and Mature Reservoir in Bohai Bay, Northern China,” by Xija Guo, Yong Jia, Kai Fan, Liuhe Yang, and Guoquan Zhao, CNOOC, and Kai Wu, Fei Wang, Cang Li, and Zhujun Gao, Schlumberger, prepared for the 2015 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Nusa Dua, Indonesia, 20–22 October. The paper has not been peer reviewed. Bohai Bay is northern China’s largest offshore basin. Its predominant depositional environment is a shallow delta and a meandering river system complicated by faults, an arrangement that leads to fully developed interbed interference and high geological uncertainty when horizontal wells are drilled within the greenfield. As a solution to resulting challenges, a new multilayer boundary-detection service has been introduced. This paper illustrates a case study in which this technology was applied. Introduction In 1967, CNOOC began commercially operating the oil and gas resources of the Bohai Sea (Fig. 1). Since then, more than 100 production platforms have been put into operation in a 43 000-km2 exploration area, including both development projects on the greenfield and infill projects on the brownfield. After long-term development and production, an increasing number of conventional reservoirs have a depleted hydrocarbon capacity and the field’s water cut has increased quickly. Thus, the CNOOC client began to focus on the complex marginal reservoir and the infill projects of the brownfield. The focus of this paper is to help achieve the geological objectives and, furthermore, optimize production by use of the new multilayer boundary-detection service. Background General Geology. The Bohai Bay basin formed at the end of the Tertiary on a crystalline basement solidified from the Archeozoic to the Early-Middle Proterozoic. After deposition in the Middle to Late Proterozoic and the Paleozoic, Mesozoic, and Cenozoic, a complex fluvial channel system was generated with features such as disconnected and isolated sand bodies, mingled structures between the hydrocarbon reservoir and aquifer, inconsistent properties both vertically and laterally, and fully developed heterogeneity. As of 1994, the Bohai Bay basin has been known to consist of 47 faulted depressions, in which 170 oil and gas fields have been found.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171896, “The Use of New Technologies To Maximize Oil Production in a Viscous-Oil Field in Arctic Environment: The Nikaitchuq Experience,” by S. Raniolo, SPE, S. Mancini, and S. Vimercati, Eni E&P; and P. Gentil, D. Simeone, SPE, and A. Buchanan, Eni Petroleum, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. Oil quality and drilling-pad constraints for a viscous-oil field defined a development scheme that consisted of a waterflood line drive with horizontal producers and water-injection (WINJ) wells side by side. Different well designs for producer wells were implemented: a single horizontal trajectory undulating between the two sand bodies in counterphase with the related water injectors, a fishbone design with the main borehole in the lower sand and multiple branches in the upper sand, and a multilateral (ML) counterphase design with extended-reach undulating dual laterals. As a result of the ML campaign, well productivity doubled. Introduction The field is located on the North Slope of Alaska in the Beaufort Sea in water depth less than 20 ft. The reservoir consists of four zones hydraulically communicating, named OA1, OA2, OA3, and OA4. The differentiation is mainly sedimentological; OA1 and OA3 are associated with a more-proximal depositional system, while OA2 and OA4 are characterized by a predominance of thin laminated silty sandstones because of a more-distal depositional system. The crude quality and drill-pad constraints (one offshore, one onshore) drove a development concept that consisted of a waterflood line drive with alternating horizontal producers and WINJ wells with a 1,200-ft spacing. The lateral sections are 6,000–10,000 ft long through the reservoir with undulating counterphase trajectories across the two main sand bodies. Challenging very-extended- reach wells with a stepout ratio higher than 6 have been achieved (Fig. 1). The undulating counterphase well trajectories were selected for producers and injectors to guarantee optimal pressure support and avoid early water breakthrough. The original design was based on predrilling assumptions; however, the reservoir was revealed to be more homogeneous than expected, with good petrophysical properties. These conditions led to the evaluation of ML concepts, with an expected low impact on water-cut trends and water breakthrough. With the goal of increasing reservoir contact, the ML concept consisting of undulating counterphase dual laterals was tested in August 2013. The producer was modified to an undulating counterphase dual lateral throughout the two main sands. The injector maintained the original well concept in counterphase with the original producer mainbore. As a result, well production doubled with respect to the average before the intervention. In parallel, key development wells were identified for data acquisition and appraisal activities that have resulted in derisking stepout opportunities as well as assessing the potential of challenging resources, such as the peripheral areas.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171856, “Net-Pay Optimization and Improved Reservoir Mapping From Ultradeep Look-Around Logging-While-Drilling Measurements,” by Frank Antonsen, Per Atle Olsen, Stein Ottar Stalheim, Monica Vik Constable, Matthieu Irondelle, Michael Cook, and Trond Rognebakke Bjørstad, Statoil, and Christophe Dupuis, Philippe Marza, Jean Seydoux, Dzevat Omeragic, and Jean-Michel Denichou, Schlumberger, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. This paper discusses ultradeep directional-resistivity (DDR) logging-while-drilling (LWD) measurements for high-angle and horizontal wells that have been applied recently with success on the Norwegian continental shelf (NCS). The main benefits from the DDR measurements in the license have been to maximize reservoir exposure by active geosteering, optimize well placement above the oil/ water contact (OWC), and increase subsurface understanding. Background More than 50% of all production wells today on the NCS are highly deviated or horizontal. An operator has tested DDR measurements since 2009. This new while-drilling technology, with its increased depth of investigation and ability to interpret multiple boundaries above and below the wellbore, is regarded as a key technology in reaching the ambitious target recovery rate of 70%. Fig. 1 presents the bottomhole-assembly (BHA) architecture for the first DDR LWD tool with depth of investigation in excess of 30 m away from the borehole. The tool architecture consists of a set of subs spaced out on a BHA providing multispacing, multifrequency azimuthal measurements. With these measurements, a multilayer inversion generates a mapping of the resistivity distribution above and below the borehole. Differentiating this technology from standard image logs, the relative dip of the formation layer can be determined not only at the trajectory, but also away from the trajectory. In addition to the 1D (layer-cake) resistivity mapping, the tool provides an orientation of the map perpendicular to the formation-structure planes.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173237, “Rapid Reservoir Modeling: Prototyping of Reservoir Models, Well Trajectories, and Development Options With an Intuitive, Sketch-Based Interface,” by M.D. Jackson, SPE, G.J. Hampson, and D. Rood, Imperial College London; S. Geiger, SPE, and Z. Zhang, Heriot-Watt University; M.C. Sousa, SPE, R. Amorim, E. Vital Brazil, and F.F. Samavati, University of Calgary; and L.N. Guimaraes, SPE, University of Pernambuco, prepared for the 2015 SPE Reservoir Simulation Symposium, Houston, 23–25 February. The paper has not been peer reviewed. Constructing and refining complex reservoir models are challenging and time-consuming tasks that entail a high degree of uncertainty. Conventional modeling work flows have remained essentially unchanged for the past decade. Such work flows are poorly suited to rapid prototyping of a range of reservoirmodel concepts, well trajectories, and development options and to testing of how these might affect reservoir behavior. A new reservoir-modeling and -simulation approach, termed rapid reservoir modeling (RRM), allows such prototyping and complements existing work flows. Introduction Hydrocarbon reservoirs typically contain an array of complex geologic heterogeneities that are at or below the resolution of seismic data, so their geometry and spatial distribution are uncertain. These heterogeneities may be structural, stratigraphic, sedimentologic, or diagenetic in origin and often affect flow behavior and hydrocarbon recovery; hence, they must be captured in reservoir models. Reservoir-modeling work flows have remained essentially unchanged for the past decade, facilitated by commercially available software packages. These work flows begin with the construction of a geocellular reservoir model, in which a largely deterministic structural and stratigraphic framework is used to define the overall reservoir volume, and compartments and zones within the reservoir. A grid is then constructed within each zone, typically using pillars that are continuous from the top to the base of the modeled volume, and using layers that may vary in thickness or be truncated by reservoir-zone boundaries. Geostatistical methods are used to populate each grid cell with a geologic indicator (such as facies or rock type) and associated petrophysical properties. The resulting models typically contain several millions to tens of millions of cells and may be upscaled onto a coarser grid before flow simulation. Despite its wide use, there are a number of shortcomings with this work flow, including Conventional modeling workflows are slow, often requiring many months from the development of initial model concepts to flow simulation or other outputs. Conceptual geologic models become fixed early in the modeling process, with uncertainty explored using geostatistical methods within the framework of a single conceptual model, rather than across a range of possible geologic concepts. It is difficult or impossible to explore rapidly a range of conceptual models, well trajectories, and development options and test how these might affect reservoir behavior. The introduction of pillar grids early in the modeling workflow limits the spatial resolution of the model and the complexity of the geologic architectures that can be captured and focuses modeling efforts on population of gridblocks with rock properties by use of geostatistical modeling methods. Geostatistical methods are often nonintuitive and require inputs that are not closely linked to the underlying geologic concept, so it can be difficult for the geologist to create a digital version of the model concept. Integration across different disciplines is made more difficult by the use of different software tools and by different model grid types and resolutions. The aim of this work is to develop RRM software for prototyping of complex reservoir models, well trajectories, and development options by means of novel, sketch-based interaction and modeling coupled with exploratory visualization and close-to-real-time numerical analysis. The new approach does not replace existing work flows; rather, it supplements them by allowing rapid testing of geologic and development concepts and how these affect reservoir behavior.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE/IADC 163485, “Offshore West Africa Deepwater Extended-Reach Drilling: Drilling-Optimization Case History,” by Hernando Jerez, SPE, Rafael Dias, SPE, and Jim Tilley, SPE, Halliburton, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5–7 March. The paper has not been peer reviewed. A deepwater extended-reach well for a major operator in west Africa required a tangent section in a soft formation. The detailed drilling plan included the use of a tailored bottomhole assembly (BHA) with a point-the-bit rotary-steerable system (RSS) and an extended-gauge bit. The BHA had to overcome the tendency of the formation to drop inclination while creating a high-quality wellbore to provide sufficient hole-cleaning capacity in the deeper sections. Introduction West Africa has seen a significant shift in drilling activity, mainly in deep water. Many of the major international operators are carrying out important exploration-and-development activities there. Typical field-development plans in offshore projects call for step-out directional and extended-reach wells, to reach and develop large areas from a single drilling platform. A solid drilling plan is required for success with an extended-reach well. The plan should be comprehensive but feasible for achieving the desired results. In this case study, the extended-reach trajectory called for the delivery of build rates in the 17½-in.-hole interval not previously reached in the shallow soft formations, building up to an 85° sail angle. For the 12¼-in. tangent interval, the BHA must hold the angle and step out the well along a faulted shale and later turn the well more than 60° in azimuth to intersect the reservoir properly. A proprietary, state-of-the-art BHA planning tool was used to model and design the appropriate BHA for each interval. Different iterations were performed to account for potential hole enlargement, build-rate response, vibration mitigation, and hole cleaning. The proposed solution was to use a point-the-bit RSS with attributes to overcome hole enlargement and deliver the planned trajectory and hole quality. The RSS was used to drill all of the directional intervals. All intervals were drilled casing to casing in one run, with one BHA per section. Case Study—Main Drilling Challenges The case-study well is an oil producer, planned to reach approximately 6800-m total depth. The main objective is to drain the reserves located in an unswept area of the reservoir that cannot be reached with conventional well profiles. The plan called for building angle in the surface hole to 85° inclination and keeping the sail angle close to the top of the reservoir, then turning 60° in azimuth and dropping to an inclination of 70°. The critical well challenges included the ability to obtain sufficient and smooth build rates in a soft formation and manage hookload and torque-and-drag loads critical to the successful stepout of the well. Another critical challenge was the narrow mud-weight window, which, on the basis of the calibrated hydraulic model, was required to control rate of penetration (ROP) to keep the equivalent circulating density (ECD) in the safe-operation window.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171792, “First-Ever Level-4 Multilateral Well in North Kuwait Successfully Completed, Improves Oil Production,” by Meshal Al-Khaldy, Abhijit Dutta, Bijan Goswami, and Ali Al-Rashidi, KOC, and Leonque Rondon, Mohamed Warraky, and Mohamed Samie, Halliburton, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. The first multilateral well in a North Kuwait field has been drilled recently. The intent is to improve oil production in productive layers subjected to water-coning problems by increasing reservoir exposure with Level-4 multilateral technology. The drilling process used a full suite of logging-while-drilling (LWD) tools, including azimuthal-deep-resistivity (ADR) technologies, to ensure the well path is precisely geosteered within the reservoir boundaries, and density/ porosity tools in real time combined with specialized modeling software, to position the well in the best possible reservoir. Introduction Drilling horizontal wells aggressively primarily using inflow-control-device (ICD) completion techniques has been prevalent in North Kuwait fields. Although some multilateral wells had been drilled in other areas, the technology had not yet been adopted in these fields. Following the successful ICD horizontal-well campaign in North Kuwait, the operator decided to implement multilateral drilling techniques in its northern fields. The initial objectives of the well are provided in the complete paper. Multilateral-System Selection Milled-window technology with control of window geometry (Fig. 1) was selected, rather than the conventional milling window. When the window is open in the casing without control, a roll-off effect occurs that generates distortion in the windows, which is likely to create operational problems during running of directional bottomhole assemblies or liners in the lateral. After comparing the Technological Advancement of Multilateral (TAML) levels and design criteria in accordance with the specific geological features from the field, the TAML Level 4 was chosen. This decision was made on the basis of the need to isolate active zones in the new lateral drilled from the window and to avoid communication between the reservoir of interest and upper layers. The TAML Level 4 is characterized by running a liner, which could be completely cemented or stage cemented, with the upper section being cemented blank liners and the lower section being slotted liners with exposure in the reservoir.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16669, ’Development Optimization of a Marginal Oil Field in Bohai Bay, China - Integrated Solutions To Overcome Challenges in Offshore Horizontal-Well Construction,’ by Chaomin Nie, Yongsheng Zhao, Lv Tan, Yong Jia, and Gang Zhai, China National Offshore Oil Corporation Tianjin, and Parlindungan Monris Halomoan, Xu Chong Hui, Wang Yong, Wang Fei, and Dong Jianyi, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28.March. The paper has not been peer reviewed. Nine horizontal wells, including one injector well, were drilled in a marginal oil field in Bohai Bay, China. Seismic inversion indicates that sand properties and connectivity vary dramatically across the field. A multiple-aquifer system was apparent, and the gas/oil-contact (GOC) and oil/water-contact (OWC) levels were unknown. Furthermore, the only well control was from three vertical exploration wells and two directional offset wells. An advanced distance-to-boundary well-placement technique using azimuthal deep-directional electromagnetic logging-while- drilling (LWD) technology was applied to overcome these challenges and to enhance reservoir understanding. Introduction The BZ oil field is located in the southern part of Bohai Bay, approximately 160 km southeast of Tanggu, Tianjin ( Fig. 1 ). It is a small oil-bearing area (9.km2) isolated by secondary faults generated at different geological periods and by stratigraphic depositional borders. Two other producing oil fields are located in the northern and western parts of the BZ area. Although the original oil in place (OOIP) of the oil field is estimated at only 1261.89×104 m3, this marginal oil field is expected to be profitable to develop and put into production by sharing the facilities of the other two oil fields. The BZ structure is part of the complex fault system on the northwest side of the Huanghekou depression on the west side of the Bonan uplift. Because of the oil field’s isolation, a multiple-aquifer system exists. A pilot study based on core and sequence-stratigraphy analysis of multiple wells shows that the reservoirs are distributary channel sands of a shallow lake delta plain. The channel sands have medium-to-high porosity and permeability. The seismic-data analysis suggests that the properties may vary laterally. Meanwhile, uncertainty in the top gas and bottom water levels adds to the complexity of this field. The GOC and OWC levels were unknown before this horizontal-well-drilling program. Horizontal-Well-Drilling Program Two platforms were designed to develop this complex oil field: BZ-A platform, to drill 11 wells, and BZ-B platform, to drill five wells. Among these 16 wells, 10 horizontal wells were designed as producer wells, five deviated wells were designed as injector wells for formation-pressure maintenance, and one deviated well was designed to supply water for the injector wells.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166087, ’Application of New Fingerprinting of Bacteria DNA in Crude Oil for Reservoir Characterization - Part II,’ by A. Hayatdavoudi, N. Chegenizadeh, A. Chistoserdov, F. Boukadi, and R. Bajpai, University of Louisiana at Lafayette, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. In the early 1980s, while the authors of the original paper were reassessing some old gravel-pack sands from a well, some sludge was noticed in the samples. The sludge had plugged formation and the gravelpack pores. The permeability was so low that the owner of the oil property considered abandoning the well and consequently stopped all workover measures, concluding that there was no more oil left in the reservoir. The scenario suggested the existence of bacteria in the oil. In the current study, a novel, sensitive technique for bacterial deoxyribonucleic acid (DNA) fingerprinting is implemented. Introduction To find bacterially induced chemical changes in oil, the research team in the first of two complete papers (only the second part is summarized here) compared the chromatograms of six carefully sampled oils obtained from two wells. The oil samples were taken directly from two wellheads without disrupting the production from the naturally flowing wells. To obtain a representative oil sample from each perforation interval, three samples were taken at different time intervals approximately half an hour apart. The distance between tops of producing intervals was approximately 3,000 ft, and the wells were designated Well A and Well B. The operator believed the two wells produced oil from the same reservoir. Despite their effective use as a tool in oil fingerprinting, chromatographic fingerprints of oil samples raised more questions than the team expected. Actually, in view of the well-known fact that oil reservoirs provide a favorable ecosystem for the growth of bacteria colonies, the precise role of bacteria in modifying the oil chemical compounds or creating new compounds could not be ascertained by use of the chromatograms. The bacterial growth indigenous to the reservoir is attributable to the abundance of nutrient, whether inorganic, organic, or a combination of both. To survive, the bacteria must adapt to conditions in which they find themselves. The process of adaptability of bacteria to their surroundings (i.e., reservoirrock minerals and reservoir fluids as nutrients under reservoir conditions) can and will change rock petrophysical properties such as zeta potential; rock wettability; relative permeability; and permeability to water, oil, gas, or other flowing fluids. Generally, the bacteria in the water phase of petroleum reservoirs possess the ability to modify the surface chemistry of rock minerals and to extract or to concentrate metal and nonmetal ions. Molecular-biology techniques have only recently been used for exploring for oil reservoirs. Recent achievements in molecular biology have extended the understanding of the role of microbial transformation and maturation of petroleum compounds under certain pressure and temperature windows and have enhanced our ability to investigate the microbial communities in petroleum-impacted ecosystems. The analyses mostly have focused on identifying the diversity of microbial species present in or on the seeps, seabed, gas vents, and reservoir waters by use of microbial 16S rRNA, a ribosome (a ribonucleic acid found in all microorganisms since the beginning of life on the planet). To identify a microorganism, its 16S-rRNA sequence information is checked against the 16S-rRNA sequence data available in the GenBank database. 16S-rRNA gene information is available for microorganisms found in different parts of the world and great distances apart such as North Sea, South American, and Asian oil fields. By use of these free gene databases, microorganisms most closely related to those which have been found in oil or gas reservoirs can be identified accurately.