During the last 20 years the drilling industry has been through extensive mechanization and automation of tasks on the drill floor previously done manually. However the efficiency of operations has not improved through this development, neither has the development been able to improve well safety, an important aspect of drilling and well operations.
During the same period the costs of rig rental and services associated with drilling operations have had a significant increase. The increased cost for drilling is an essential aspect in the discussion of oil recovery from existing reservoirs and in the decision to explore new structures, thereby affecting the oil revenue of oil companies and governments. The importance of lowering drilling costs has been clearly pointed out at various industry conferences.
Mature oil provinces will experience an unnecessary decrease in oil production due to extensive drilling costs. The ability to reduce these costs is urgent and is heavily addressed by the major operators. Significant more drilling is necessary to prolong the production on the many mature fields
As the drilling for oil and gas is moving into more demanding areas the need for safer drilling practices is imminent. The drilling industry has after several accidents a need for improved equipment that yields a higher standard in well safety.
West Drilling Products AS has invented and patented a new generation drilling technology - Continuous Motion Rig (CMR), a technology that promises a significant breakthrough in drilling efficiency, cost savings and well safety. CMR technology has a potential to reduce drilling time with 50 % and overall drilling costs with 40 - 50 %.
The main principle in this new breakthrough technology is to be able to run jointed drill pipe and casing continuously, to drill continuously while maintaining circulation. The CMR technology facilitates Underbalanced Drilling, MPD, and full snubbing capabilities. CMR will be the first fully robotize drilling process.
This paper will present the CMR technology, the development status and that the CMR Technology is a valuable and visible contribution of lowering drilling costs and introducing higher standard in well safety.
This paper summarizes a three-year research on the overtrawlability of pipe-in-pipe, and develops the method to access it. Overtrawlablity is the ability of the pipe to resist the trawl gear impact and the pull-over force. The trawl gear will first impact the pipe and then pull over the pipe. If the overtrawlable capacity of the pipeline is insufficient, the trawl gear may damage the pipeline by denting or bending the pipe heavily. Overtrawlability of the pipeline has a direct bearing on whether the pipeline needs to be protected by burial with significant cost savings if burial is not required.
DNV-RP-F111 and the other industry guidelines give a method to estimate the overtrawlability, but currently there is no method specifically for pipe-in-pipe. The outer pipe gives the inner pipe extra protection, and it does not have to resist internal pressure and can therefore accommodate a greater level of indentation than a single-wall pressure-containing pipe. If we apply the approach for the single wall pipe to pipe-in-pipe, the results are likely to be conservative. Therefore, an assessment of the overtrawlability of pipe-in-pipe is necessary to be conducted before making any trenching decisions, and to avoid providing unnecessary protection.
With this motivation, a three-year JIP has been conducted at the National University of Singapore to better understand the overtrawlability of pipe-in-pipe, and to find the method to assess it. The research includes three different experiment programs to investigate the impact and pull-over responses. FE models of indentation and impact are developed and validated against first-hand experimental data. A new relationship of load-deflection relationship is developed to assess the impact response. External pressure is considered by the FE model using hydrostatic fluid element. Small scale pull-over experiments are conducted to study the pull-over force for different pipes and different conditions.
The research work altogether develops the way to analysis the response of pipe-in-pipe when it interacts with a trawl gear. Finally, A comparison between a pipe-in-pipe and a single wall pipe shows the difference between them and throws light on the issue of trenching for pipe-in-pipes to some extent.
As oil and gas extraction has reached increasingly deep water in recent years, floating platforms are now more widely used than conventional facilities. The mooring of floating systems can be problematic since significant vertical loading is imparted to the foundation systems. Consequently many different types of anchors have been developed to resist the pullout forces, and compared with conventional anchors SEPLA (suction embedded plate anchor) is more widely used because of its lower cost and shorter installation time.
The vertical uplift capacity of plate anchors has been studied extensively. However most of the studies were based on theoretical and numerical analysis or tests in 1g conditions. In the present paper, 50g and 100g centrifuge model tests are performed to analyze the pull-out behavior of plate anchors in normally consolidated soft clay and the soil flow mechanism during the uplift process.
The anchor is idealized as square in shape. Load-displacement curves and vertical pullout capacity are obtained in a series of wish-in-place tests. The contributing factors are also examined, with special attention paid on the anchor embedment ratio (H/B). Half-anchor tests are performed to study the soil movement patterns surrounding the anchor during the uplifting process, by using PIV (particle image velocity) method and the close range photogrammetry technique. Results are presented in the form of capacity factor (Nc) and are also compared with previous numerical and empirical solutions. Full-flow mechanism (soil flows around the anchor with local failure in shear) is observed in the half-anchor tests.
This study with centrifuge model test provides insightful information on the uplifting pullout capacity of plate anchors as a part of foundation systems of floating platforms, as well as the flow and failure mechanism of surrounding soil.
Barasia, A. (Schlumberger Asia Services Ltd) | Singh, M. (Schlumberger Asia Services Ltd.) | Kasturia, S. (Schlumberger Asia Services Ltd) | Christiawan, A. (Schlumberger Asia Services Ltd) | Venkateshwaran, R. (Schlumberger)
The main basin at East coast of India, Khrisna-Godavari (KG) Basin, is spreaded across more than 70,000 sqkm. on land, shallow and deep water and holds India's highest gas reserve. Deel Dayan East (DDE) field is part of KG Basin in which lay deep HPHT tight gas reservoir that with current drilling and completion technologies can be made viable. An offshore appraisal well was directionally drilled down in S-shaped to the depth of 18700 ft MD to appraise the hydrocarbon potential of Lower Cretaceous Early Rift Fill sequences which was encountered in one of the offset wells in the same field DDE Block.
Due to typical extremely tight nature of sandstone reservoir on deep gas well, hydraulic fracturing is the primary method and become inseparable technique to complete this well. Given its HPHT nature, with BHT up to 415F and insitu stress up to 16000 psi, also the complexity of hydraulic fracturing on limited space of Jack-up rig, the hydraulic propped fracturing project become extremely challenging, both technically and operationally. In addition the limited flexibility on logistic due to short drilling time constraint, made some available fracturing HPHT technology not an option for this project, and require creative domestic solution. There were 3 independent reservoir layer were hydraulically fracced till the end of the well project, and significant gas were tested on post fracture completion from none prior to fracture.
This paper illustrates the meticulous planning and preparation to design and execute the hydraulic propped fracturing for well testing appraisal purpose, as collaboration works from operator, fracturing services provider and other third party involved. The core objective of this paper is to capture all lesson learnt during this project delivery, review project operational and technical aspects, and summarize the recommendation and applicable techniques for the similar offshore HPHT hydraulic fracturing project in the future.
The use of Dope-Free tubulars in offshore operations have been increasingly adopted by different operators since its debut in the North Sea in 2003.
Dope-Free tubulars replaces the storage and running pipe dope historically used in Casing and Tubing by a dry coating applied on pipe threads in an industrial controlled environment.
The elimination of dope simplifies greatly the supply chain of the preparation of Casing and Tubing for offshore increasing the efficiency, safety and lessening the environmental impact of the process.
The main benefits of this technology are: - Improved Operational efficiency - preparation, running, pulling management of rig returns; - Reliability: connections are installed in a more consistent and repetitive manner as the coating is an industrial process replacing a manual operation; - Improve well productivity: eliminating the damage to the formation created by the pipe dope and Health Safety & Environment .
Operators experience, after a short learning curve, showed great reductions in installation time, reduction on connections re-make ups and rejects, improvement on workers’ Health & Safety conditions by eliminating unsafe tasks and creating cleaner work areas, and minimization of the Environmental impact.
This paper describes the experiences and benefits of the use of Dope-Free tubulars in offshore operations in the main offshore oilfields including the North Sea, the Barents Sea, Brasil, Indonesia, Gulf of Mexico and the Persian Gulf.
Dong, Xiaohu (China University of Petroleum, Beijing) | Liu, Huiqing (China University of Petroleum, Beijing) | Zhang, Zhaoxiang (China University of Petroleum, Beijing) | Lu, Chuan (China University of Petroleum, Beijing) | Fang, Xin (China University of Petroleum, Beijing) | Zhang, Gaige (China University of Petroleum, Beijing)
Due to the water-coning problem, cycle steam stimulation (CSS) in the heavy oil reservoirs with bottom water is often less effective, and the oil recovery is even below 10%. Steam assisted gravity drainage (SAGD) is the oil-producing process with a constant pressure-drop (about 0.30 MPa), and it is a potential technique for this reservoirs. Through the implementation of SAGD, bottom water could be effectively controlled.
Aiming at the heavy oil block of LD5-2N in Bohai offshore oilfield, the SAGD performance in heterogeneous heavy oil reservoir with bottom water was numerically studied in this paper. In these simulation models, the water was broken into three components (connate water, injected water and bottom water) to study the water producing in SAGD process. Thus, the influences of startup approach, oillayer thickness, water thickness and the distance between well-pair and bottom-water on the water rising were all simulated. Thereafter, a set of numerical simulations were performed to assess the shale issues in SAGD process, e.g. the vertical and horizontal position of shale-barriers, the shale distribution range, the barrier permeable condition and the macroscopic vertical
Results indicated that bottom water reduced the ultimate recovery of SAGD process by about 10%~20% of the OOIP. The startup by steam-circulation was much suitable for the bottom water heavy oil reservoir instead of CSS approach. The bottom water tremendously reduced the startup pressure-decline rate, and thus the startup-time was prolonged. The distance between well pair and water zone had a great influence on the SAGD performance, and a small distance would delay the beginning time of the steam-chamber rising. For reservoir heterogeneity, the vertical and horizontal heterogeneity have great influence on the drainage process, especially the shale cases. It tremendously decreased the recovery rate by about one time.
This investigation could be used as a tool for the successful design of SAGD process in heavy oil reservoirs with bottom water.
Jamaluddin, M.S.R. (Petronas Carigali) | Hanalim, L. (Petronas Carigali) | Suwarlan, W. (Petronas Carigali) | Permanasari, D. (Schlumberger) | Santoso, G.I. (Schlumberger) | Brahmanto, E. (Schlumberger) | Lwin, M.M. (Schlumberger) | Alang, K.A. (Schlumberger)
Most of the hydrocarbon bearing sands in Angsi, Malay Basin, have been identified as thin sands with average thickness of less than 8-m. Thus, reservoir development has become challenging. One of the effective ways to develop this field is by drilling highly deviated or horizontal wells. Based on the field study, water injection was the chosen technique to manage the reservoir pressure during depletion in the reservoir.
After long production, one of the thin reservoirs in Angsi has become highly depleted and was in critical need of injection. This reservoir is distributed widely in the field, with an average thickness of one meter. Due to the sand thickness, the most efficient way to place an injector well is to drill horizontally in the depleted part of the reservoir. However, placing a horizontal well in this depleted thin sand posed significant challenge for the drilling operation, including to land accurately at the target sand, avoiding premature exit from the target reservoir due to geological uncertainties, and managing the borehole pressure to avoid differential sticking of the BHA. For formation evaluation, the high angle effects such as anisotropy, close vicinity to shoulder beds, and lateral property changes will make the quantitative interpretation more complex.
To address the challenges, a combination of logging-while-drilling measurements namely near-bit gamma ray, average and deep directional resistivity for boundary detection, azimuthal density, neutron porosity, and formation pressure measurements were used to land and optimize the well in the thin sand, executed by a collaborative experts from subsurface, drilling, and geosteering team. High angle well modeling was also conducted to extract the true formation properties and explain the high angle effects to the measurements. As a result, the well was placed optimally in the thin target reservoir for 300-m length as per objective, with improved quantitative petrophysical evaluation.
In this case study, the comprehensive work from pre-drill planning, drilling execution including 24 hours real-time monitoring to steer the well, to post well evaluation and modeling will be discussed. Lessons learnt, best practices, and recommendation of drilling and evaluating similar well will also be shared in this paper.
In subsea business, the use of wetgas flowmeter is becoming a standard for deep and ultradeep field development. The business growth is outstanding over the last few years and it is expected to continue at the same path. Furthermore, the tieback of these fields to hosting platform or onshore facility has increased drastically. The critical measurement is not only on high accuracy flow rates but also on water detection with 99.x% of the production being gas. The liquid is initially predominantly condensate phase continuous before becoming more watery with the well ageing. Water is the main concern either in presence of H2S or because hydrate could be formed and will plug the production line . To counterbalance these catastrophic scenarii the chemical use is necessary, but the cost leads to loss of benefit, therefore an optimization is necessary. The need for a reliable water detection became a compulsory practice with constraint to be working initially in oil and water continuous phase. The innovative solution describes in this paper look at how an accurate measurement could be offered at any GVF and WLR based on the use of two different types of measurement having a different response to the water-hydrocarbon contrast and water conductivity sensitivity.This approach led to a development of an innovative add-on on the wet gas meter which provides a high accurate local water fraction measurement that can be comparing with a global measurement. This paper is focusing on the explanation of this innovative analysis after 10 years of work in this direction, and the value brought to oil/gas operator in detection of water and then optimizes the use of expensive chemical. It is also possible to identify clearly, if the water is coming from the formation or not in any WLR mix. It addresses also the use of MPFM beyond the classical metering flow rate performance and focus on the benefits of brought for a subsea flow assurance and reservoir management.
Heidari, Mohammad A. (Islamic Azad University Science and Research branch) | Habibi, Ali (University of Tehran) | Ayatollahi, Shahab (University of shiraz) | Sohbatzadeh, Farshad (University of Mazandaran)
Wettability is always an important issue for reservoir engineers. Wettability alteration is one of the significant indexes to show the capability of oil recovery of reservoir. In the recent years, various approaches to change wettability have been suggested by scientists and researchers such as chemical flooding and nanofluid injection. The purpose, in oil wet condition, is to change wettability to water wet condition to obtain more recovery. A lot of different methods for wettability measurement such as Contact Angle, Amott methods and USBM are proposed by Anderson and others. The most accurate method is contact angle for wettability measurement.
Plasma is one of the four fundamental states of matter. Heating a gas may ionize its molecules or atoms thus turning it into a plasma which contains charged particles: positive ions and negative electrons or ions. A nonthermal plasma is in general any plasma which is not in thermodynamic equilibrium, either because the ion temperature is different from the electron temperature or because the velocity distribution of one of the species does not follow a distribution. The effect of cold atmospheric argon/oxygen plasma torch based on dielectric barrier discharge was investigated on different surfaces. The experiments were conducted on the mica, glass slide and slice of dolomite core surface which is aged with oil and without oil and on a dolomite core with oil after waterflooding. The time interval of plasma torch treatment on these surfaces were 1, 3 and 5 minutes and contact angle measurements done 1, 14 and 28 minutes after plasma treatment. The range of contact angle decrease is between 5 to 41 degree and Fourier Transform Infrared Radiation (FTIR) spectroscopy was carried out for analysis of surface chemistry. It is worth mentioning, however, that it is a novel method and requires more investigation in order to be feasible in reservoir conditions.
The offshore oil and gas industry is continuing to push into deeper water and onerous environments, using increasingly complicated vessels and equipment.This, combined with changing global weather patterns has increased uncertainty in offshore production operations. Monitoring mooring lines can help reduce this uncertainty by calculating fatigue damage estimates during major storm events. This greater understanding helps to optimise inspection and maintenance schedules and assess the likelihood of future mooring line failures. Added to this, if the deterioration or failure of a single mooring line is not detected, increasing loads on the remaining lines may result in additional failures. This is regarded as a system failure and could lead to significant consequences for both well control and riser integrity, resulting in huge costs for operators. Unless the operator inspects on a regular basis or monitors the mooring system in real time it is impossible to know for certain whether all mooring lines are in place.
A popular technique for monitoring mooring systems is to measure mooring line angle (using accelerometer based inclinometers), to infer theoretical mooring line tension. Whilst these systems are effective at alerting operators to a line failure, the fact that tension must be inferred requires a certain amount of conservatism in the estimate. This conservatism can be difficult to quantify. This paper documents the sea trial of a well proven mooring connector combined with new mooring line technology capable of measuring both mooring line angle and direct line tension. This allows for a unique comparison between the two measurements. This paper will detail the results of this comparison, showing the accuracy of inclination based monitoring systems and the level of conservatism factored in when tension is inferred. The data published in this comparison can be used to reduce levels of uncertainty in offshore operations and thus reduce future levels of conservatism in design and analysis models. This can help save costs and increase efficiency for future operations, whilst also helping support safety strategies.