Rig Costs Research Articles

Hybrid Gas-Lifting Method Optimizes High-GOR Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209721, “Hybrid Artificial Lift-SRP/Gas Lift for Oil Production in High-GOR Environments,” by Kuldeep Chanchlani, SPE, Ranjit Gogoi, and Sukumar Awasthi, SPE, ONGC, et al. The paper has not been peer reviewed. _ The casing gas-pressure-operated rod-lift (CGPORL) system described in the complete paper consists of a sucker rod, pump, gas-lift valves, downhole gas anchor, and tubing string. The completion was invented to save workover rig cost, reduce production deferments, and increase production efficiency in high-gas/oil-ratio (GOR) environments in marginal fields. CGPORL System Description The hybrid-lift system includes gas-lift and rod-lift modes, allowing operators to switch between two modes of artificial lift without costly workovers (Fig. 1). The key factor is the ability to isolate or communicate between the tubing and the annulus without pulling the tubing string out of the hole. Gas lift requires that the annulus should isolate tubing in order to inject gas through valves installed inside pocket mandrels, whereas rod pumps need communication between the tubing and annulus for passage of liberated free gas. Mechanism The gas-lift valve opens once annulus pressure develops over the valve-closing pressure. Once free gas is released into the tubing and the injection valve is closed, the annulus becomes a closed system. The free gas released from the downhole gas anchor gradually pressurizes the annulus until the valve opens for the next cycle. This mechanism indicates an intermittent gas-lift process in a cycle. When the well ceases to flow because of rod-lift failure, the well When the well ceases to flow because of rod-lift failure, the well will continue to flow through the annulus by keeping open the annulus valve connected to the nonreturn valve. Because of the nondevelopment of annulus pressure in case of rod-lift the CGPORL system. failure, a mobile air compressor can be used for valve unloading until the rod pump can be serviced. As the solution gas is recombined with liquid above the pump-setting depth, the hydrostatic head is relatively decreased. If the gas-lift valve is placed at a shallower depth, the drilled well length contributing to the reduction of fluid density is short. If the pump is placed at a deeper depth, annulus pressure can be high, so the gas-lift valve can be placed in a low position. Optimization for the point-of-pump setting and gas-lift-valve setting depth is required. These effects are related directly to the frequency of injection and rate, which must be examined along with economic and safety factors.

Economic Analysis and Generic Algorithm for Optimizing the Investments Decision-Making Process in Oil Field Development

Due to the substantial amounts of money involved and the complex interactions of a number of different factors, managers of oil and gas companies are faced with significant challenges when making investment decisions that will increase business efficiency and achieve competitive advantages, especially through cost control. Due to the various uncertainties of the current period, optimal investment strategies are difficult to determine. Thus, through an economic analysis that includes data analysis, quantitative risk analysis scenarios, modelling and simulations, a work framework, in the form of a generic algorithm, is proposed with the aim of generating a complex procedure for optimizing investment decisions in oil field development. A complex set of elements is considered in the analysis: costs (operational expenditures (OPEX) and capital expenditures (CAPEX), daily drilling rig costs), prices (oil, gas, separation and water injection preparation), production profiles, different types of taxes and discount factors. Above all, oil price volatility plays an essential role and creates uncertainty in relation to profitability and the strategic investment decisions made by oil exploration and production companies.

Tutorial: A Century of Sidewall Coring Evolution and Challenges, From Shallow Land to Deep Water

Due to the high cost of conventional coring operations, rotary sidewall coring has become increasingly important, particularly for deepwater operations. The rig costs, operational challenges, and amount of time involved to core wells below 30,000 ft are considerable, even for wireline operations. As wells get deeper, formation pressures will exceed 30,000 psi, and differential pressures can exceed 10,000 psi, which will eclipse the capabilities of traditional rotary coring tools. New technology has been introduced to enhance the recovery of rotary sidewall cores to improve operations and capabilities on these challenging wells that will be the primary subject of this paper. This new technology can also enhance coring operations and reliability for land and other offshore operations, in addition to deep water. New improvements and challenges include: * Reliable 1.5-in.-diameter core samples, with a 35,000-psi-rated tool * New high-powered coring tools with enhanced energy to address cutting Lower Tertiary wellcemented formations (Wilcox, Lower Miocene, etc.) * Higher torque and horsepower at the bit to enhance cutting and prevent stalling when coring * High-powered surface systems along with highstrength and high-power wireline cables * Upgrades to address high temperatures, highdifferential pressures, high-mud viscosity, large (24 in.) boreholes, and improved reliability * New drill bits and catcher rings to use a high-power system and operate in harsh coring environments * New cutting, retrieval, and core handling advancements for reliability in hard, consolidated formations * Combinability upgrades to reduce wireline trips and reduce rig costs for coring * Dual-coring tools with the ability to have different catcher rings and bits downhole simultaneously on a single run, along with tool redundancy downhole for improved reliability * Combination of rotary coring and formation sampling operations to obtain formation pressures, fluid samples, and rotary sidewall cores on a single run * Downhole monitoring of the coring operation, which includes drilling functions like torque, bit force, penetration rate, core bit penetration, and recovered core length, along with tool orientation * Core recovery information to enable 100% core verification downhole, so extra cores are not cut unnecessarily during the job, with individual core plugs measured and verified downhole * A unique method to seal the cores in a pressurecompensated coring tube downhole to capture all the formation fluids in the rock in downhole conditions * Complete rotary coring downhole operations can be monitored remotely for offsite interaction during the coring operation Besides reviewing historical coring tools and techniques, new technology is also discussed in more detail. The new technology starts with the introduction of the 1.5-in.-diameter rotary sidewall coring tools for deep water over a decade ago. Many applications and technologies are presented to show their effectiveness for deepwater operations. The successful examples include acquiring 1.5-in. cores in large boreholes, hard formations, deep wells, high-differential pressures, and extreme hydrostatic pressure. There are also examples of new technology available for future operations, including dual coring, combination coring, and sealed pressurized coring.

Lined tubing performance in CSG wells operated in Australia

One of the major challenges with progressive cavity pump (PCP) applications in Australia is the production of highly concentrated solids. Large volumes of solids entering the production string cause both high torque issues and holes in tubing, resulting in lost production and the need for intervention with a flush-by unit or service rig. On account of these issues, it is reported that up to 40% of PCPs in the Australian coal seam gas (CSG) fields can be down at any given time. Coho Resources has introduced lined tubing as an engineered solution. The proprietary lining the tubing has a lower friction factor compared with conventional steel tubing, resulting in lower operational torque and reduced operating costs. The added lubricity from the lower friction coefficient in lined tubing allows solids to flow more freely to surface where they are captured and discarded from the system. Lined tubing allows producing companies to realise bottom-line operational savings in several ways. The largest of course is minimal downtime and reduced well service costs due to the elimination of our previous tubing related problems. With reduced work over costs, savings become visible very quickly. Rig costs, bottom hole pump, tubing and sucker rod replacement costs are all reduced. Application of lined tubing in CSG wells in Australia results in: • 15–25% less torque on the drive system, • An 70% increase in run times between workovers (lined tubing versus un-lined tubing), and • Compatibility with existing field equipment and handling methods.

Monitoring of Quarry Drill Rig Costs and Proposals for Their Reduction

This article deals with issues of the quarry drill rigs operation. They are the rigs with top hammer, or down the hole hammer drills, primarily used during the preparation of blasting. The article is focused on the monitoring of costs and economic management. The introductory part of the article provides a description of all costs, and their division to fixed and variable costs. In the next part, figures of particular costs are provided for specific selected locations in the Czech Republic. Also, the article deals with proposals for the monitoring, evaluation, and reduction of the costs. Separately, the fixed costs are covered, with the evaluation of turn points in various conditions. The proposals for the reduction of variable costs are provided separately. In the article conclusion, summary of recommended measures is provided. Key words: drill rig, costs monitoring, blasting.

Real-Time Data Analytics Allows for Bit-Wear Monitoring and Prediction

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 189602, “Real-Time Bit-Wear Monitoring and Prediction Using Surface Mechanics Data Analytics: A Step Toward Digitization Through Agile Development,” by Yu Liu, Justin Kibbey, Yanbin Bai, and Xianping Wu, SPE, Shell, prepared for the 2018 IADC/SPE Drilling Technology Conference and Exhibition, Fort Worth, Texas, USA, 6–8 March. The paper has not been peer reviewed. Severe bit damage is an issue in West Texas land drilling because of abrasive sand formation and interbedded hard stringers. Operational performance and rig costs often are affected by bits damaged beyond repair (DBR), low rates of penetration (ROPs) with worn bits, and inefficient decision-making regarding tripping. A real-time data-analytics application is developed that aims to provide information to operators to expedite decision-making. Introduction As bottomhole-assembly (BHA) design and bit selection have become standardized, a historical data set of surface mechanics data and bit records has been accumulated from 40 bit runs. By combining conventional physical modeling of drilling mechanics and supervised machine learning, a hybrid analysis is conducted to separate bit-failure patterns from normal formation transitions and drilling-parameter adjustments. A metric-based algorithm is constructed for real-time monitoring of bit performance and for predicting bit wear. A lightweight web-based framework is used for deployment in real time. A shadow mode trial on three wells in the same pad was conducted and generated satisfactory results. Agile-Development Framework The agile-development framework is an integrated platform for fast technology prototyping, which consists of the following components: The Amazon cloud server is the platform for the application repository, computing-engine execution, and data stream and storage. Most real-time data-analytics applications are delivered as software-as-service, where the algorithm-processed data is stored on the cloud server and pertinent results are delivered to end-users over the web. User interaction with the web application is limited to default viewing options, and other data exchanges such as value inputs are kept to a minimum to reduce complexity. MATLAB and Python are the engines for algorithm development, prototyping, and early-stage deployment. MATLAB is a powerful engineering computing/coding program with strong capability in data management, visualization, and debugging. It provides various toolboxes for signal processing, machine learning, and statistical analysis. Python is an alternative to MATLAB with similar functionality and the advantage of being open source. Codes of data preprocessing, core algorithms, and data stream input/output (I/O) are realized in the MATLAB environment running on the Amazon cloud server. Wellsite Information Transfer Standard Markup Language (WITSML) I/O is the industrial standard for drilling-data stream and management. In this application, surface mechanics drilling data are streamed into MATLAB using a WITSML wrapper. Plotly is a solution for visualization on the web and user interface. Computation results from MATLAB are delivered to a web page by calling Plotly functions within the MATLAB environment.

Fibre-Optic Vsps: Borehole Seismic Revolution in Australia

The borehole seismic industry is undergoing a quantum leap in the acquisition technology. The standard borehole seismic imaging tools such as accelerometers and geophones are now being replaced by the fibre-optic (FO) acquisition for basic surveys such as zero-offset vertical seismic profiles (ZVSPs) and checkshots. This saves significant time, and associated rig cost, whilst providing sufficient data quality for basic interpretation. Schlumberger’s heterodyne distributed vibration sensing (hDVS) technology, deployed within a wireline heptacable, was recently used in Australia to acquire a zero-offset VSP dataset, whilst simultaneously taking downhole core measurements. The hDVS technology is based on the distributed acoustic sensing (DAS). This presentation shows the acquired dataset and the basic processing results. A comparison between the FO and conventional dataset, in the nearby wellbore, as well as surface seismic and synthetics is made showing remarkable similarity between all datasets, validating the FO data.

Optimization of core retrieval using a Thermo-Poro-Elastic (T-P-E) approach

One most common cause of damage of the recovered cores occurs during their fast decompression from the bottomhole to the surface. This occurs as sufficient time is not allowed for the pore fluids in the center of the core to dissipate than in the annulus. As a result, excessive pore pressure difference and stresses are induced in the core body. This may cause tensile failure which shows itself as microfractures in its body. These microfractures adversely alter the core rock and mechanical properties.Therefore, the sample should be retrieved/tripped slowly enough so that the induced pore pressure and stress difference do not become excessive and the core does not undergo tensile failure. On the other hand, this slow enough retrieval rate should meet the operational rig costs so that it does not cause invisible lost time. Therefore, the optimal tripping rate should be determined for each case. This should be used as the basis of coring method/tool candidate selection. The industry has so far utilized only generic methods for selecting their core tripping schedules and thus their coring methods (used for coring tool candidate selection). Just recently, there has been some research in this regard which failed to consider the thermal, mechanical, and mud cake effects, they did not also evaluate the induced stresses and the optimal rates.Therefore, in this work, a state-of-the-art T-P-E model is developed and applied to evaluate the optimal tripping rates. This work includes: 1) the modeling, derivation, and evaluation of the hydraulic and thermal effects including the neglected ones in the literature, i.e., the thermal, mud cake, and the mechanical properties, 2) summing-up of all the effects to produce the induced stresses, 3) comparing the induced stresses with the tensile strength, 4) indicating whether tensile failure occurs for a specified tripping rate, and 5) repeating the trial and error process for different tripping rates until the optimal rate can be obtained. Therefore, in this work, a standard procedure is proposed to optimize the retrieval rate by requesting a standard set of inputs and running the model for different tripping rates.In addition, during the modeling process, the contributing parameters have been identified. Having found the contributing parameters, using rig site data including the cuttings analysis (which is used to estimate several input parameters), it is not possible to find the value of the hydraulic diffusivity with certainty. So far, the magnitude of the tripping rate (finding the optimal value of which is the objective of the work) has been controlled just arbitrarily by the drilling crew. Therefore, these two parameters have been introduced as the main uncertain parameters and thus the sensitivity analyses of their effects have been investigated. Using this analysis, some extremes for tripping rates have been introduced, which can be used as a general engineered guideline for coring tool/method candidate selection.

Field Deployment of a Rigless Cable-Deployed Electric Submersible Pump Using a Vertical Wellhead

Summary Electric submersible pumps (ESPs) are a widely used artificial-lift technology. Conventional ESP systems provide power with a cable banded to the outside of the tubing. These systems have drawbacks in terms of installation speed and efficiency. To overcome these obstacles, a novel cable-deployed (CD) ESP system developed for use in a production environment with high hydrogen sulfide (H2S) content is presented as a future solution. This paper focuses on the challenges, results, and lessons learned from the first field deployment in the world of a rigless high-H2S CD-ESP system. A metal-jacketed power cable was a key enabler to the CD-ESP system. The metal-jacketed power cable delivers the best protection for an H2S attack and provides a smooth outside diameter that could be gripped on and sealed. The cable had been tested to withstand H2S levels up to 15% in the vapor phase and chloride levels in excess of 150,000 ppm, with an expected service life in excess of 10 years, derived from laboratory testing. To overcome well-control concerns, a vertical cable-hanger spool (VCHS) was developed to enable the ESP cable to be terminated below the master valve. In addition to the surface termination of the cable, the VCHS provided hang-off and production-flow-through capabilities. The CD-ESP system, using a specialized inverted ESP, required close integration between several equipment and service providers during the development of equipment and procedures to ensure success in the installation of the system. The system's initial deployment was in a benign onshore well that offered ample workspace for the various service providers to learn the unique aspects of this rigless deployment. The interface between the service providers at the surface-cable termination was critical to the successful installation. For this trial test, the well completion was changed from 4½-in. tubing to 7-in. tubing to accommodate the CD 562 Series ESP. Lessons learned from this field trial will be incorporated into future trials of the technology. The goal of these future trials will be to deploy the technology in offshore H2S wells where high rig costs can be significantly reduced by using a lower-cost barge coupled with increased speed, efficiency, and ease of CD-ESP deployment.

Technology Update: Retrofitting MPD Systems to Deepwater Rigs Aids Drilling, Efficiency, and Process Safety

Technology Update The unique properties of deepwater formations pose significant challenges to the capabilities of conventional drilling rigs. By retrofitting rigs with automated drilling systems, including managed-pressure drilling (MPD) equipment, operators and contractors in global deepwater basins can optimize efficiency and economics while maintaining the level of safety that the industry and regulatory community have mandated for this high-stakes arena. MPD, an adaptive drilling process that actively controls annular pressure throughout the wellbore, is increasingly being integrated into the risers of existing deepwater drilling vessels (Fig. 1). It is the cornerstone of an automated well-control strategy that augments and enhances standard well-control protocols. The technique provides distinct drillability, efficiency, and process safety benefits in deepwater environments. It addresses the higher level of priority that the industry has placed on process safety, which largely involves the ability to accurately and actively monitor and control operations while drilling. Long used in land and shallow-water drilling, MPD-ready rigs are proving their value in deepwater operations by delivering a reliable level of automation and process control when the risk of a well-control incident is highest. Fluctuations in wellbore pressure often create drilling hazards that result in lost circulation, kicks, and other problems that can significantly increase rig time and cost, or lead to catastrophic well-control incidents. An automated MPD system installed onto a deepwater semisubmersible rig or drillship can effectively monitor and maintain the annular hydraulic pressure profile by applying common MPD variants, such as constant bottomhole pressure (CBHP) and pressurized mud cap drilling (PMCD). The ability to continuously monitor various wellbore parameters—particularly those related to downhole pressure—while drilling and making connections also enhances personnel preparedness by serving as an extra set of eyes to supplement those of less-experienced drillers. While expanding the drilling envelope and monitoring wellbore pressure profiles, an MPD system that provides automated advanced flow detection, including early kick detection, also reduces the risks of human intervention by mitigating the possibility of gas in the riser.

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.

Technology Update: Magnetic Resonance-While-Drilling System Improves Understanding of Complex Reservoirs

Technology Update Reservoirs consisting of heterogeneous carbonates and shaly sands pose formation evaluation challenges for conventional logging-while-drilling (LWD) measurements. Widely used resistivity, density, neutron porosity, and sonic measurements are all sensitive to both the formation matrix and the fluids, which may create ambiguities in the evaluation of reservoir fluids. The Schlumberger proVision Plus magnetic resonance-while-drilling (MRWD) technology offers enhanced evaluation capabilities. By manipulating the hydrogen atoms in the fluids, nuclear magnetic resonance (NMR) methods provide a focused measurement of fluid properties and their interactions with the surrounding matrix at a fundamental level. The technology provides a more complete, real-time assessment of producibility in complex reservoirs. Evolution of the Technology The industry has used NMR technology for formation evaluation for more than 25 years, during which significant technical and operational developments have greatly enhanced its capabilities and applications. In porous media, NMR techniques reveal pore and fluid properties by exciting the nuclear states of hydrogen-containing molecules in the formation fluids and measuring the relaxation times for the induced excited energy states. The relaxation time for a molecule near a pore wall surface tends to be much faster than that for a molecule in the bulk fluid volume. A distribution of all the relaxation times, known as a T2 distribution, can be used to derive both irreducible and producible fluid volumes, and an improved estimation of permeability. These measurements are also important for identifying bypassed pay zones and estimating production rates. The first NMR tools were deployed on wireline after the hole had been drilled, which added rig time and cost to the operation and did not allow for real-time changes to the wellbore’s trajectory. Schlumberger shifted the service from wireline to a while-drilling application in 2002. This early work focused on redesigning the sensor array to make it more robust and capable of withstanding dynamic drilling environments. The design effort culminated with the introduction of the company’s latest MRWD system in 2012. Its new sensor makes reliable measurements under rapidly changing downhole temperatures and pressures and withstands the vibrations and drillstring shocks that are common during drilling. Further design enhancements allow the tool to be placed anywhere within the bottomhole assembly (BHA). A sleeve stabilizer minimizes tool motion without affecting the steerability of the BHA. Powered by a downhole electrical turbine, the tool does not need to be tripped to replace batteries.

Model for economic replacement time of mining production rigs including redundant rig costs

Purpose – The purpose of this paper is to present a practical model to determine the economic replacement time (ERT) of production machines. The objective is to minimise the total cost of capital equipment, where total cost includes acquisition, operating, maintenance costs and costs related to the machine’s downtime. The costs related to the machine’s downtime are represented by the costs of using a redundant machine. Design/methodology/approach – In total, four years of cost data are collected. Data are analysed, practical optimisation model is developed and regression analysis is done to estimate the drilling rigs ERT. The artificial neural network (ANN) technique is used to identify the effect of factors influencing the ERT of the drilling rigs. Findings – The results show that the redundant rig cost has the largest impact on ERT, followed by acquisition, maintenance and operating costs. The study also finds that increasing redundant costs per hour have a negative effect on ERT, while decreases in other costs have a positive effect. Regression analysis shows a linear relationship between the cost factors and ERT. Practical implications – The proposed approach can be used by the decision maker in determining the ERT of production machines which used in mining industry. Originality/value – The research proposed in this paper provides and develops an optimisation model for ERT of mining machines. This research also identifies and explains the factors that have the largest impact on the production machine’s ERT. This model for estimating the ERT has never been studied on mining drilling rigs.

Cement-Integrity-Evaluation Solution in Extended-Reach Wells in the South China Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25027, “Solution to Cement-Integrity Evaluation in Long Extended-Reach Wells: New Record in the South China Sea,” by Jun Cai, Yongde Gao, and Mingjie Zhang, CNOOC, and Lei Cui and Hongzhi Guo, SPE, Schlumberger, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25–28 March. The paper has not been peer reviewed. The combination of ultrasonic pulse-echo and flexural-attenuation measurements was adopted in this project in the South China Sea for cement-integrity evaluation. This new method aids in understanding why integrity losses occur in certain sections, by analyzing third-interface information uniquely provided by flexural-wave imaging, and in formulating improvement actions for future cementing jobs. This method achieves a more-explicit cement-integrity-evaluation result with detailed graphical annulus information compared with the limited output from conventional acoustic measurements. Introduction In the Weizhou field in the South China Sea, most of the development wells are drilled as long extended-reach wells with a deviation greater than 70°. The wells are designed to reach more than 70° deviation at a very shallow depth (approximately 900 m) compared with the total depth of the well (approximately 4500 m). In a typical well, surface casing (13.375 in.) runs beyond the kick-off point and reaches maximum deviation of the well at a shallow depth (approximately 900 m). Intermediate casing (9.625. in.) runs from surface to more than 4000 m, with three different fluids/ slurries pumped in the annulus: regular-weight tail cement (1.90 g/cm3), freshwater displacement cement, and lightweight lead cement (1.58 g/ cm3). The completion liner (7 in.) hangs on the intermediate casing, with 1.90-g/cm3 cement pumped in the annulus. A campaign was planned to perform cement-integrity evaluation in five wells (A9, A10, A1, A2, and A3). The basic information about these five wells is listed in Table 1 of the complete paper. The objective for Well A9 was to evaluate the 7-in. completion casing, and the objective for the remaining four wells was to evaluate the 9.625-in. intermediate casing. The well profile and completion pose several challenges: Cementing highly deviated wells has uncertainties associated with cement placement because of the likelihood of poor mud removal, which is generally caused by pipe eccentering. Intermediate casing is cemented with both regular-weight and lightweight cements. A more advanced method to evaluate the material in the annulus independently of its density is required for this project. The geometry of casing in the borehole is important information in this type of well because it is the main factor affecting the cement placement in the annulus. The logging tool string is not able to be conveyed by wireline only because of the high deviation along the wellbore. An alternative conveyance needs to be performed in an efficient manner.to save rig cost. For a discussion of the conveyance-selection process that resulted in the selection of a wireline tractor, please see the complete paper.

Changing the path of mini-DST through an advanced wireline formation testing technique: first application in the Asia Pacific

As the oil and gas industry moves towards new ventures and remote locations, possibly in more challenging reservoirs and in high-cost, high-risk environments, a cost-effective formation testing method is fundamental to assess new findings and proper decision making. Despite its ability to provide precise pressure profiles and multiple samples obtained along reservoir sections, wireline formation testing is generally seen as complementary to extensive well test operations. Determination of reservoir viability with wireline testers is often considered only indicative of reservoir productivity, while testing techniques through straddle packers are perceived as not totally risk free. Information obtained from a well test often depends on the reservoir type. If most of the heterogeneous carbonate reservoir warrants comprehensive testing to evaluate productivity through natural fractures, evaluation of homogeneous sandstone is generally an assessment of matrix permeability. An advanced formation testing technique was used for the first time in a 12.25-inch bore hole in the Asia Pacific region. An effective mini-DST was carried out by delivering an inflow performance relationship (IPR) consistent with the known production behaviour of the Laminaria Formation in the Kitan oil field in a cost-effective manner compared to the traditional straddle packer technique. In addition, this case study points out that under certain circumstances, mini-DST results from a specific interval of the reservoir can be scaled up to the whole reservoir under investigation, making this technique potentially an alternative to a full well-testing program, when rig costs or environmental constraints often make such a procedure prohibitive.

Operational efficiency improvement by using logging while drilling (LWD) fluid sampling and pressure-testing device

Abstract An operator in Asia Pacific required a large sample volume from a gas reservoir for accurate non-hydrocarbon gas (NHCG) content analysis from two extended reach wells. This extended abstract highlights the use of an LWD fluid sampling and formation pressure-testing device to overcome numerous challenges, including a highly deviated wellbore, stuck pipe, oil-based mud (OBM) gas-sampling issues, and prevention of geo-chemical absorption. Application The choice to use an LWD fluid sampler was based on several factors that reduced significant risks. Due to the well’s deviated nature, the only traditional wireline fluid sampling solution would have required a pipe-conveyed logging mechanism. This would have added rig days to the project and increased the risk of stuck pipe. To prevent geo-chemical absorption, the storage tanks were manufactured with a specialised metallurgic design. This would be tested by applying a customer-requested coating to half the tanks and monitor differences in geo-chemical content. To prevent differential sticking, testing sequences would be limited to 90-minute intervals. Results, observations, and conclusions After two runs in separate wells, a total of 25 samples were acquired containing more than 19 litres of fluid. Due to the reduced invasion profile as a result of LWD technology, fluid stability was reached within the 90-minute threshold. Furthermore, results showed only 8% OBM contamination—half the amount seen in offsets from wireline produced fluid samples. Finally, due to the improved operation efficiency and the quality of the samples, the customer estimates that it saved nearly $10 million in rig costs and millions more in reduced retrofitting costs of the production facility. Significance of subject matter This extended abstract highlights a major step-change in fluid sampling technology. Operators no longer need to consider a well’s deviation in the ability to collect fluid samples. The recap of the two wells will offer additional best practices and risk mitigation techniques for future LWD sampling projects. It also adds yet another LWD technology that provides consistent wireline equivalent data.

Walkabove VSP with seismic-while-drilling technology: flawless operation in a highly deviated well

SWD was recently used in the North West Shelf of Australia to acquire time-depth measurements and to obtain a vertical seismic profile (VSP) while pulling out of hole. The use of SWD technology greatly enhanced the understanding of geology by acquiring a more precise geophysical picture of the subsurface, leading to better understanding of the subsurface and placement of wells in the future. A vertical incidence VSP was acquired in an offshore deviated well for a client on the Australian North West Shelf. The data was acquired using a moving-surface source, suspended from a boat, and a four-component downhole sensor in the bottom hole assembly (BHA). The downhole data was acquired using three orthogonal geophones and a single hydrophone measurement at each VSP level. This was recorded while pulling out of hole, and processed once the tool was on surface. Time picking accuracy of the downhole data is ±0.5 ms with the frequency range 6–90Hz, both comparable to Wireline. The repeatability of the hydrophone and geophone time picks was also excellent with the average difference being 0.2 ms and maximum 0.8 ms. High resolution VSP images beneath the well in addition to corridor stacks were derived from the geophone and hydrophone data, showing the geological structure of the reservoir. The quality of the data acquired allowed the client to remove the need for a wireline VSP run; it, therefore, saved significant rig time and costs associated with it, reduced the chances of getting stuck, and significantly reduced the seismic uncertainty.

World's Deepest Through-Tubing Electrical Submersible Pumps

Summary This paper describes the development, history, and successful deployment of the world's two deepest through-tubing-conveyed electrical submersible pumps (TTCESPs). These are the first TTCESPs deployed inside of 7-in. casing. Electrical submersible pumps (ESPs) are a form of artificial lift that consists of a pump, motor, and electric cable, typically deployed by a rig and connected to electric power at surface. Their advantage is that they create greater drawdown than other forms of artificial lift, thus achieving higher production rates. However, conventional ESPs require expensive workover rigs to replace pumps, the component that fails most frequently. ConocoPhillips Alaska developed TTCESP technology to replace failed pumps rapidly and economically. In this system, a rig conventionally deploys the electric cable, motor, and seal sections with a special latching device for the pump. The pump is pulled and replaced with slickline (wireline) or coiled tubing, eliminating the requirement of a rig. The original through-tubing-conveyed (TTC) systems were developed for 7⅝-in.-cased wells. During approximately the past 10 years, it was common belief that they could not be deployed at the Milne Point field in Alaska because of the limitations of its smaller wells (7-in., 26-lbm/ft casing). This paper discusses the enabling technologies that were developed to allow running TTCESPs in 7-in. casing, including a wellhead spoolpiece and low-clearance ESP clamps. West Sak TTCESP run-time data indicate that the time between rig workovers (RWOs) will increase from 3.5 to 6 years. Pumps can be replaced for 5–10% of rig costs without the safety and environmental impacts associated with rigs. Additionally, production impacts while waiting for a rig are eliminated because slickline and coiled-tubing units are readily available on the North Slope of Alaska. TTC pumps can easily be upsized or downsized to optimize pump flow rate because of changes in production rates. This technology is of interest in areas where rig costs are high, including Arctic, remote, and offshore locations. It is also beneficial where rig availability is low.

Increasing Drilling Efficiencies Through Analysis of Real-Time and Historic Drilling Data

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128722, ’Increasing Drilling Efficiencies Through Improved Collaboration and Analysis of Real-Time and Historical Drilling Data,’ by Catheryn Staveley, SPE, and Paul Thow, SPE, Schlumberger, originally prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. The paper has not been peer reviewed. Estimated spending on drilling and completions was more than USD 250 billion in 2008. With rig costs estimated to consume 37% (or USD 92.5 billion) of that spending, every effort to reduce drilling time has a direct effect on the bottom line. Estimates of nonproductive time (NPT) ran from 15 to 40%, or USD 14 to 37 billion, depending on well type and operator. The causes were varied and included technical and nontechnical challenges. Obviously, any effort made to reduce NPT will affect bottom-line spending. Introduction The oil and gas industry spends millions of dollars each year collecting vast amounts of drilling data, yet has not made effective use of these data to improve drilling performance. Drilling analysis is a proven technique for improving the return on investment of drilling operations, but comprehensive drilling analysis has not been a regular part of well planning and operations. So why is it that comprehensive drilling analysis is not a consistent part of drilling best practices? In part, perhaps, because of the culture. One author suggested that 95% of drilling activities are operationally focused, placing emphasis on doing, rather than planning or analyzing. Many people in drilling operations thrive on operating by “gut instincts” and succeeding through heroic efforts. While experience dealing with unexpected events is crucial for success in an environment where uncertainty exists, surely it would make more sense to be taking pride in telling stories about the well where everything went according to plan. Furthermore, while most companies have health, safety, and environmental policies that are “zero-tolerance,” an acceptance of waste and inefficiency as being inevitable in drilling operations continues. It is difficult to imagine another industry that would accept 60% waste when it is widely known that something as simple as better planning can improve drilling results. Two other key obstacles to integrated drilling analysis are the inability to manage the volumes of data that potentially could be used in drilling analysis and the historical limitations of traditional well-planning software. The vision for integrated drilling analysis includes the ability to: Visualize and correlate low- and high-density data. Allow effective sharing of cross-discipline expertise. Provide continuous real-time updates. This integrated approach includes technologies to overcome data-management challenges and well-planning limitations, and to implement multi-disciplinary work flows to help facilitate planning and analysis across an asset team.

Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124324, ’Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments,’ by Waitus Denham, SPE, Shell, and Brian Donadieu, SPE, Ernest Lee, SPE, Rohit Mathur, SPE, and Ananth Srinivasan, Baker Hughes, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. New drilling opportunities require technological innovations to increase efficiencies and optimize production. Some newer drilling operations, particularly in deep water, involve extreme environments such as ultrahigh pressures that require new approaches. With downhole pressures approaching 30,000 psi and escalating rig costs, rotary-steerable systems (RSSs) and advanced formation-evaluation technologies are needed. Introduction Advances in rig design, in downhole tools, in data communications, and in other areas result from challenges associated with pushing and extending limits. While in the planning stages of a deep-water high-pressure well, risk mitigation and contingency planning are critical in making technology advances. It is important to balance the drive to advance technology with the value created. Solution Potential In many cases, wellbore construction can be accomplished with standard off-the-shelf products and services. When the location moves into deep water, the complexity, risks, and costs of those operations require fit-for-purpose or application-based solutions. In this case, early in the design phase of the well, increased potential of a high-pressure situation was evident that would require equipment that was unavailable at the time. Therefore, the operator approached a selected vendor and began a feasibility study. Open communication between the companies was critical. After developing an understanding of the operator’s critical success factors, the service company gained clearer insight into the challenges at hand and was able to address the effects and risks associated with “new” technology. Development Stage Typically, well-construction planning involves a few key individuals from both companies. For this case, it was important to involve additional sup-port and expertise to ensure success. Expanded teams from the operator included the drilling, geology, and petrophysical disciplines, along with asset-management and offshore-operations experts. The vendor expanded its operations, applications-engineering, and technical-support functions to include reliability engineering, product development, quality management, repair, and maintenance.