APIT is a computational software based system which performs real-time test analysis, reporting and automated result interpretation of FITs/LOTs/XLOTs based on surface and downhole data. This paper presents the challenges for the current pressure integrity testing and introduced a new solution called automated pressure testing (APIT) system. This has included system framework and integration to cementing units, models and algorithms to determine system compliance and fluid leakage, fracture closure pressure, calibration techniques and validated results. Based on a minimum of preconfigured user input, the APIT system covers all test phases, from pressurization, fracture propagation to shut-in and flowback. The system identifies unexpected test behavior and triggers warnings by continuously evaluating key test metrics such as leakage rate, system compliance and surface pressure during each test phase.
This APIT system was tested optimized and validated using various historical field data in order to provide Proof-of-Concept of algorithms, test sequences and graphics user interface (GUI). Both successful and unsuccessful data chosen from NCS and the international arena were tested. The automatic interpretation algorithms from APIT are aligned with manual test interpretation performed internally in Statoil.
The APIT system is believed to be a safer and more efficient pressure testing alternative to the current manual counterpart.
Development of Giant carbonate reservoir considerable cap gas and condensate reserves along with oil rim is now being considered as one of the on-hand options to overcome shortage of gas in the long term and to add value to the company assets. This paper presents an overview of the study that was initiated to assess the feasibility of the simultaneous development of gas and oil and to evaluate its impact on the existing oil long term development plan.
A compositional simulation study has been conducted by adding the co-development of the gas cap on top of the current Long Term Oil development plan. This development includes water injection at the original gas oil contact level to isolate the gas cap and to enable to develop gas cap independently from the oil rim. In this scenario, drilling of producers in the gas cap is considered and condensate is produced to the dedicated production system. Several prediction scenarios have been investigated to set up a development plan of gas: Blow down or natural depletion, Produced gas recycling, Lean gas recycling.
Blow down or natural depletion,
Produced gas recycling,
Lean gas recycling.
The best scenario has then been selected for further optimisation. (On gas injection recycling ratio, project start-up timing, gas production target, and water injection).
After analysing the results, it was found that the blow down of the gas cap provides a good recovery of gas and condensates but has a negative impact on oil reserves.
Gas recycling option proves interesting as it maintains pressure both for condensate (hence preventing drop-out) and for oil; therefore impact on Black-Oil recovery becomes minor.
Oil recovery is higher with late starting time of the co-development or with high recycling ratio. Oil Recovery Factor depends mainly on the pressure maintenance of the reservoir. However excessive gas injection has a negative effect due to breakthrough of the gas into the oil producers which have GOR limit constraints.
Co-development simulation study of the gas cap along with oil, through an inner ring of water injection at gas oil contact shows that the co-development is not only feasible but it will also bring significant value to the company future business plan. Gas cap being semi-isolated from the oil rim, the impact on the oil development plan is minimized.
Co-development proves appealing to the different owners of the field since it brings more gas and LPG that is foreseen as valuable source of enriched gas for later EOR or WAG schemes
Production from oil fields requires monitoring of hydrocarbon saturation in the reservoir. In the Bockstedt oilfield there exists a substantial difference in resistivity between oil-filled (approx. 100-16 Ohmm) and brine-filled (0.6 Ohmm) reservoir. Electromagnetic method is chosen to test whether sufficient resistivity differences can be observed via surface measurements. The target is a Lower Cretaceous clastic interval located at an approximate depth of 1200 metres.
Forward modelling demonstrates that the expected resistivity changes at reservoir level cannot be resolved with a survey setup of only surface electrical sources and sensors. Therefore a borehole-to-surface technique has been developed, whereby the metal casing of an abandoned production well serves as input electrode. CSEM surveys were acquired in 2014 and 2015 as timelapse baseline and monitor for both Ex and Ey components. Forward modelling indicates that induction effects from metal objects like casings of production wells cannot be ignored in the EM modelling. A shallow observation well was drilled in 2015 to make collection of Ez datasets possible. A new downhole sensor was developed for this purpose. Numerical simulations suggests Ez data is more sensitive to the anticipated resistivity changes. Since Ez is two orders of magnitude smaller than the horizontal components, verticality is of great importance to avoid masking the Ez signal by interference from unwanted horizontal components.
Similar acquisition parameters are adopted for 2014 baseline and 2015 monitor surveys to facilitate the comparisons. The repeatability is good, generating comparable response functions. The earth model, retained so far by the inversion algorithm, confirms the main resistivity units seen by the resistivity logs in the calibration well. Incorporation of the metal casings in the EM modelling scheme increases the lateral continuity of inverted resisitivity bodies.
This study is a follow-up of work presented in the 2015 ADIPEC conference. In November 2016 a new acquisition campaign will be undertaken to collect a second Ex – Ey monitor and the first monitor survey for the Ez component. A limited time-lapse test has been performed in spring 2016 to monitor Ez with only 1 source station incorporating the borehole electrode Bo-23.
Mahmoud, Mohamed (King Fahd University of Petroleum&Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum&Minerals) | Shawabkeh, Reyad (King Fahd University of Petroleum&Minerals) | Bahgat, Mohamed (Well Flow International)
Iron sulfide scale is a common scale in sour oil and gas wells. It can form in wells producing oil and gas, as well as water injection wells. Iron sulfide scale has different forms based on the iron-to-sulfur ratio. Iron sulfide scale can form in soft forms that are removed easily by acids such as phyrrotite. The scale can also form in hard forms such as pyrite that is difficult to remove by acids. Several attempts have been made to investigate the removal of different forms of iron sulfide. Scale can reduce production and injection rates. At the end, it may completely plug the tubing and the only remedy will be to change the tubing. In the previous work either low pH corrosive fluids were used or high pH fluids with low solubility.
In this study, we introduced a new formulation to remove the iron sulfide scale (especially the hard scale) pyrite form of the iron sulfide. The new formulation has a pH value greater than six with low corrosion rate. Solubility, stability, as well as corrosion experiments, were performed to assess the new formulation. The new formulation is based on a chelating agent and a low pH fluid mixture. Also coreflooding experiments were performed on carbonate cores to assess the performance of the new formulation if it invaded the near-wellbore during scale removal operations.
The XRD of actual scale sample from a gas producer well showed that the scale sample contains 43 % pyrite, 35% mackinawite, and 22% iron silicon compounds. The scale solubility reached 81.6% using the new formulation. The new formulation remained stable for more than 48 hours at a high temperature. The corrosion rate of actual tubing coupons was 0.03 lb/ft2 without using corrosion inhibitors at 125°C/257°F. This corrosion rate within the allowable limit for the industry standards (should be less than (0.05 lb/ft2). Coreflooding experiments showed permeability enhancement using the new formulation which eliminates the risk of using this chemical in scale removal because it will not cause formation damage to the near-wellbore if it invades the formation.
In this study, various upscaling techniques and their effects on Barik tight gas Formation simulation modelling results were investigated. The intent of this upscaling study is to recommend coarse models that provide approximately the same flow behavior or well performance as the fine grid model. The study will help to develop an awareness of the range of applicability for the upscaled coarse models. It will also allow coarse grid models to be used appropriately and with greater confidence in production optimization.
These techniques comprised several alternative ways of grouping reservoir data, with respect to petrophysical rock types (herein referred to as RT). This scheme defines 5 individual rock types, with RTs 1 to 4 broadly defining pay and RT 5 defining non-pay.
The layers in the simulation models are made up of single or multiple grouped RTs from the same zone. Keeping each layer in the model, ordered as it was in the well log, resulted in 85 simulation layers for the fine grid model. The upscaled or coarse models have 16 to 35 simulation layers, with the smallest being the model where RTs 1 to 4 are grouped together. Different RTs sorting were tested in each of the upscaled models.
The results of this study suggest that re-ordering the log information so that all of the rock for each rock type was grouped together inside each stratigraphic unit appears to be an acceptable upscaling technique that gives reasonable efficiency and accuracy. This type of upscaling was required since the study showed that any upscaling method that averaged the properties of RT 1 with the properties of other rock types within the same simulation layer could result in optimistic EUR estimates of up to 30% relative absolute error when compared to a fine grid model. The choice of upscaling method is particularly significant in a low Kv/Kh ratio environment, but less so within environments with a high Kv/Kh ratio.
The upscaling technique has only been tested for the Barik formation and should not be used elsewhere without proper testing. The upscaling technique works for the Barik formation because of several distinctive features of the reservoir and the wells. In applying this upscaling technique we assume that: The wells are all hydraulically fractured and thus the flow is generally horizontal into the fractures and from the fractures into the well. The fracture extends from the top to the bottom of each stratigraphic unit that the fracture encounters. If a fracture only partially penetrates a stratigraphic unit, this method may not work. The gas is relatively dry and thus the flow is less affected by gravity than for reservoirs containg flowing liquids. The reservoir is made up of rock with a wide range of permeability, but the flow is dominated by the well connected, higher permeability rocks (RT 1). The reservoir is very stratified, and the correlation length of the rock types has to be very much greater than the well spacing.
The wells are all hydraulically fractured and thus the flow is generally horizontal into the fractures and from the fractures into the well.
The fracture extends from the top to the bottom of each stratigraphic unit that the fracture encounters. If a fracture only partially penetrates a stratigraphic unit, this method may not work.
The gas is relatively dry and thus the flow is less affected by gravity than for reservoirs containg flowing liquids.
The reservoir is made up of rock with a wide range of permeability, but the flow is dominated by the well connected, higher permeability rocks (RT 1).
The reservoir is very stratified, and the correlation length of the rock types has to be very much greater than the well spacing.
Re-ordering of the RTs in a given upscaling method will result in acceptable accurate estimates of hydrocarbon recovery, compared to the fine grid model. It showed that the order of layering did not matter for the area studied, because a conductive fracture connects all the layers. This method probably really is only applicable for dry gas reservoirs (where gravity is not important) and in fractured wells (where horizontal flow into the fractures and into wells dominates). In oil reservoirs and rich condensate reservoirs where gravity is an important factor, the ordering of the rock types within the simulation layer may matter.
It will also be shown that an approximately 90% reduction in the simulation modelling computing time could be achieved if the appropriate upscaling technique is used. To achieve this reduction in computing time, some compromises were made, including assuming RT 4 is non-pay in upscaled models where RTs 4 & 5 are grouped together in the same simulation layers, resulting in reduction of HCPV. It is important to mention that some RT 5 zones in the log have thin instances of other rock types, which are not accounted for in the upscaled models and could result in an error in average pore volume preservation.
During the recent decades, a significant number of multi-laterals wells with smart completions controlled by different flow control technologies has been installed worldwide. This case study is based on a reservoir developed completely with multi-lateral wells. Each well is completed with three to seven laterals with different flow control technologies.
The study covers an analytical methodology and a multiphase flow model to optimize production that has multi-lateral wells equipped with flow control devices. Optimizing the complexity of this system, and understanding the contribution of each lateral during commingled production, has become a challenging process and is the main objective of this study.
A multi-lateral well modelling process was developed to obtain a representative model, which can predict accurate results under different operational conditions. The paper also covers a well test procedure, which is essential to guarantee the good quality of the data and ensure representative results.
This methodology covers two main factors affecting multi-lateral productivity, which are a flow dependent gas-oil ratio (GOR) rate and interference between the laterals.
The multilateral production optimization process was developed successfully to represent the operational conditions and optimize the well for different scenarios based on their specific reservoir management strategy. This model was extended successfully from a single to a multi-well model, including their actual surface facility network. The model will be considered in future production strategy plans.
Omar, M. G. (Baker Hughes Inc.) | Boushahri, M. Yacoub (Kuwait Oil Company) | Ghanim, A. (Kuwait Oil Company) | Al-Osaimi, M. (Kuwait Oil Company) | Dixit, R. (Kuwait Oil Company) | Mubarak, S. (Kuwait Oil Company) | Taqi, G. (Kuwait Oil Company) | Taha, M. (Baker Hughes Inc.) | Abdelhamid, A. (Baker Hughes Inc.) | Agawani, W. (Baker Hughes Inc.) | Lee, R. (Baker Hughes Inc.) | Valbuena, F. G. (Baker Hughes Inc.)
With an objective to shorten directional intervals, operators place greater demand on higher Build Up Rates (BURs). The section just before the pay zone involves the most intensive directional work, pushing rotary steerable systems to their capability limits. This paper focuses on a particular interval of hard and soft interbedded carbonates that provides a significant challenge for conventional Polycrystalline Diamond Compact (PDC) bits to provide consistent build up rate and good borehole quality on rotary steerable systems. Throughout this paper we demonstrate the engineering process of designing a bit to increase buildup rate capabilities of rotary steerable systems and improving drilling efficiency through interbedded carbonate formations.
The engineering process involved reviewing the critical issues of this application to assure a sound solution. This included:
Current build up rates versus Rotary Steerable Systems (RSS) steering capability. Vibrations generated by conventional PDC bits being deployed in the field. Specific cutting structure, depth of cut limiters and gauge requirements for different RSS drive types. Formation strength analysis. Parameters used in drilling the section. Roller cone insert and PDC interaction of the hybrid bit with the formation and how formation deformation generated by one interacts with the other. Roller cone insert design aimed specifically at carbonate formation drilling
Current build up rates versus Rotary Steerable Systems (RSS) steering capability.
Vibrations generated by conventional PDC bits being deployed in the field.
Specific cutting structure, depth of cut limiters and gauge requirements for different RSS drive types.
Formation strength analysis.
Parameters used in drilling the section.
Roller cone insert and PDC interaction of the hybrid bit with the formation and how formation deformation generated by one interacts with the other.
Roller cone insert design aimed specifically at carbonate formation drilling
Various hybrid drill bit and Bottom Hole Assembly (BHA) combinations were evaluated with state-of-the-art drilling response simulator to review the buildup rate capabilities combines with the bit and BHA interaction. The best combination was then successfully trialed on several wells, proving significant improvement compared to current performance with conventional PDC bits.
The optimized hybrid bit and BHA combination eliminated drilling vibrations in intervals where extreme vibrations were witnessed with conventional PDC bits, significantly increasing drilling efficiency. Improved torsional stability reduced the load on the directional tools improving the ability to achieve the required doglegs. In softer shale where RSS with conventional PDC's had to control parameters while using maximum steer force to achieve target dog legs of 7°/100ft, the hybrid drill bit achieved 10°/100ft while utilizing only 70% of the steer force. The hybrid drill bit has been proven to be successful with both push-the-bit and point-the-bit RSS systems.
Hybrid drill bits have proven to be a solution to problems and limitations of both conventional PDC and roller cone bits in directional drilling. Based on recent refinements in the drilling mechanics of hybrid drill bits to further improve their interaction with directional drilling systems, engineering selected this emerging technology to overcome the challenges in this particular application.
Al Hosani, Fahad (Zakum Development Company ZADCO) | Amin, Alaa (Zakum Development Company ZADCO) | Ali, Yasser (Zakum Development Company ZADCO) | Al Kiyoumi, Ahmed (Zakum Development Company ZADCO) | Sau, Rajes (Zakum Development Company ZADCO) | Beckham, Richard (ExxonMobil Upstream Research Company URC) | Shuchart, Chris (ExxonMobil Upstream Research Company URC)
A giant oil field offshore has been developed to date using vertical and then horizontal wells drilled off-shore from wellhead platform towers. In order to reduce costs reducing the number of wells required to drain the reservoir with improving recovery, further development of the field was planned using extended-reach long horizontal wells with throws greater than 18,000 ft and measured depths greater than 25,000 ft with some wells exceeding 35,000 ft.
This paper will discuss how to reach an integrated robust completion design methodology to maximize performance of these long horizontal wells. The methodology considers a combination of two essential designs; Lower completion design and Stimulation design.
While the key objective of lower completion and stimulation designs has been to connect wells to reservoirs at their best performances with the most effective and economical way, productivity/injectivity from every foot of these long laterals as well as long term performance are the keys to successful well design and reservoir development strategy. The design methodology incorporates several constraints from reservoir such as heterogeneities in permeability, pressure and porosity, and uncertainties in those properties prediction including presence of faults/thief zones. The design methodology also incorporates the objective to be able to perform well surveillance, such as PLTs, as well as manageable installation of lower completion. The paper will give examples of application of this methodology in designing a10,000+ ft long limited-entry liner which facilitates bullhead high pressure – high rate stimulation – high acid concentration in order to place acid across the entire lateral and maximize stimulation effectiveness of every foot of the lateral. The paper will also discuss actual well performances of available long lateral wells along with lessons learned.
Iwama, Hiroki (Abu Dhabi Marine Operating Company) | AL-Silwadi, Basil Mohamed (Abu Dhabi Marine Operating Company) | AL-Feky, Mohamed Helmy (Abu Dhabi Marine Operating Company) | Nakashima, Toshinori (Abu Dhabi Marine Operating Company) | AL-Shehhi, Omar Yousef Saif (Abu Dhabi Marine Operating Company) | AL-Neaimi, Ahmed Khalifa (Abu Dhabi Marine Operating Company)
This paper introduces the history matching process of commingled wells and demonstrates how to reduce the uncertainty of the vertical permeability ratio (kV/kH) by analyzing the production logging results of horizontal wells which have been used only for allocation through the evaluation of horizontal well performance.
The field discussed in this paper is an offshore carbonate oil field located to the Northwest of Abu Dhabi. In this field, a lot of horizontal water injectors have been drilled and completed for the purpose of reservoir pressure maintenance. Historically, most of horizontal water injectors were completed as comingled injector covering two layers isolated by thick dense layers. Due to the complexity of the well and the difficulty of well monitoring, the well performance of these horizontal water injectors was not fully integrated into the model history matching process.
The kV/kH ratio is one of the important parameters for analyzing fluid movements in carbonate oil reservoirs. Generally, the value obtained from core analysis results is utilized for reservoir simulation models. In this paper, the effectiveness of analyzing production logging results for commingle wells is introduced as a method for evaluating kV/kH on the simulation model. The end result can reduce uncertainties of kV/kH resulting from heterogeneity of carbonate reservoirs.
It is confirmed that production logging results of commingle horizontal wells are valuable for evaluating kV/kH to be defined the simulation model. They can help to reduce the uncertainty in kV/kH, although there is not enough data for the history matching process.
As a part of GASCO strategy to launch joint initiatives in field testing of latest available NDT technologies with the lowest cost required, and in order to explore the most reliable alternatives in the industry for higher inspection accuracy of non-piggable piping & pipeline with the aim of validating these for future adoption across company's operating sites, GASCO has successfully completed a pilot project using state-of-the-art mini-pigging (InVista technology) for non-piggable pipelines.
The InVista intelligent mini-pigging technology incorporates new high-fidelity ultrasonic probes and provides high accuracy in estimating quantitative wall thickness data vis-à-vis the relatively outdated UT Tethered in-line inspection technology. The InVista technology benefits are summarized as follows; Provides practical solution for non-inspectable pipeline and piping. Achieves higher accuracy in data than the conventional inspection technology. Operates at minimum to no risk and also significantly reduces the downtime of these assets, which is a substantial cost optimizer. Provides a medium to long term perspective for a cost-effective asset integrity management (Cost saving approx.60%).
Provides practical solution for non-inspectable pipeline and piping.
Achieves higher accuracy in data than the conventional inspection technology.
Operates at minimum to no risk and also significantly reduces the downtime of these assets, which is a substantial cost optimizer.
Provides a medium to long term perspective for a cost-effective asset integrity management (Cost saving approx.60%).
GASCO performed a pilot project using InVista technology to inspect a non-piggable 8" carbon steel underground fire water line (1.8 Km length) in Buhasa plant, which has never been inspected since 1980.
The InVista inspection results have been confirmed via UT site verification survey for the selected locations where the survey results were matched with the InVista results.