To overcome horizontal well reservoir and production challenges, inflow control devices are adopted as the optimal completion method in many parts of the world. The main industry drivers for adopting inflow control device completions include balancing inflow along the well, delaying water and gas breakthrough, controlling water and sand production, and providing a cost-effective reservoir completion solution to meet the majority of the reservoir challenges. In offshore Saudi Arabia, inflow control devices have been used successfully in fulfilling these objectives. The downhole completion efficiency is evaluated using multiphase production logging tools.
Many completion accessories can be run with inflow control device completion strings, these include isolation packers, liner hangers, setting tools, end-of-completion string plugs and valves. All of these accessories may affect the well’s production performance. New challenges arise when one of these accessories, such as the end-of-completion valve or isolating packers malfunction and develop a leak; thus, affecting the inflow control device completion performance. A major failure can result from such a malfunction, including fluid drainage from the toe section, sand production, early water breakthrough and water coning.
This paper presents two field examples in which multiphase production logging profiles of horizontal wells are used to evaluate the inflow control device completion performance and detect any completion-accessory malfunction. Multiple sensitivity simulation runs — supported by multiphase production logging results — facilitate optimizing the inflow control device completed well performance. This integrated approach is used to recommend solutions or remedial actions to overcome sub-optimal well completion performance. Also, the approach provides a comprehensive understanding of the reservoir results that should be considered in planning future completion and workover strategies.
Rafie, Majid (Saudi Aramco) | Said, Rafit (Saudi Aramco) | Al-Hajri, Muhammad (Saudi Aramco) | Almubarak, Tariq (Saudi Aramco) | Al-Thiyabi, Adel (Saudi Aramco) | Nugraha, Ikhsan (Saudi Aramco) | Soriano, Eduardo (Halliburton) | Lucado, Jared (Halliburton)
In Saudi Arabia, conventional oil reservoirs have been treated using conventional stimulation methods. The challenge is that many of the formations now are tighter and require improved stimulation methods. Fracturing is a major topic discussed in the industry as of late and as such, using it in this formation will serve as a trial to shift from conventional stimulation methods to fracturing when facing tighter formations.
This particular acid frac was performed in a tight carbonate formation. The chosen well is a newly drilled trilateral producer completed with a multistage frac completion in the motherbore and will serve as a pilot well for this reservoir in the area. The acid frac was a seven stage completion utilizing hydraulic fracturing. Several methods using pressure and injection were used to determine reservoir fracturing response and petrophysical properties.
This paper will discuss the first multistage acid frac performed in an oil producer in Saudi Arabia. It will examine the entire process of candidate assessment, job preparation, and execution. In addition, the paper will discuss challenges faced, solutions taken, and the post-decision results. The paper will show how an injectivity test performed pre- and post-frac was used as a benchmarking tool to analyze the effectiveness of the frac. Finally, we will discuss the flow back of the well, initial results, lessons learned, and optimization of future jobs.
Shale gas is natural gas that is found trapped within shale formations. Shale gas has become an increasingly important source of natural gas in the United States since the start of this century, and interest has spread to potential gas shales in the rest of the world. In 2000 shale gas provided only 1% of U.S. natural gas production; by 2010 it was over 20% and the U.S. government's Energy Information Administration predicts that by 2035, 46% of the United States' natural gas supply will come from shale gas. Some analysts expect that shale gas will greatly expand worldwide energy supply. China is estimated to have the world's largest shale gas reserves. This paper covers a detailed study on the following topics:
This paper also discusses different shale gas case studies which include seismic techniques, well log analysis, reserve estimations techniques, hydraulic fracturing techniques, production optimization and simulation. The objective of this paper is to give an understanding and insight of shale gas reservoirs.
The growing demand for gas in the Kingdom of Saudi Arabia and the availability of multistage fracturing (MSF) of horizontal well technology have opened up the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently using MSF strongly depends on well spacing, especially for low permeability reservoirs. The majority of the work done by the industry to find the optimum well spacing was based on economic considerations. Saudi Aramco optimizes field development based on sustained rate and ultimate hydrocarbon recovery. Natural gas is treated as one of the most essential commodities supporting the country’s infrastructure based on the increased domestic energy demand.
Some of the significant parameters to consider for well spacing optimization are the drilling azimuth and well completion strategy that include a number of induced fractures, fracture conductivity, and fracture half-lengths. In addition, reservoir properties, such as formation thickness, reservoir permeability, and the permeability anisotropy ratio are to be considered. Due to the scarcity of interference test data in gas wells and the inaccuracy of analytical solutions, numeric simulation is the most suitable approach for such a study. To find the optimum well spacing, several simulation runs are carried out for a realistic range of well and reservoir variables. The outcomes are then translated into a 20-year cumulative production as a function of the well spacing, with the results indicating that lower permeability reservoirs require closer well spacing. In the case of a large number of long fractures, wells need to be placed further away from each other to minimize well interference. This paper gives the recommended MSF horizontal well spacing for several development scenarios in Saudi Arabian gas reservoir environments. Although each area must be individually studied and optimized, the results will provide engineers with guidelines to better plan gas field development with the application of MSF technology.
In conventional cyclic steam stimulation (CSS), steam is periodically injected at high pressure to the reservoir. After the steam injection period, the well is soaked for several days then it will be produced. Generally, for the first to the fifth cycle, the steam can effectively transfer the heat to the reservoir. After that, the CSOR will rise up indicating that the process is currently ineffective.
This paper aims to improve the CSS performance using modified well completion. The perforation is modified to become two parts, one part is on the top side (as injection) and the other part is on the bottom side (as production). In this process, after being injected, the steam will condense, resulting from heat loss, and it will move to lower part because of gravity drainage. Simultaneously, crude oil was produced through the production perforation. The opening-closing of the injection-production cycle is managed by interval control valve (ICV). To provide an overview of this phenomenon, a synthetic reservoir model was built based on Pertama-kedua formation, located in Sumatra Indonesia. Sensitive variables are length of the injection-production perforation and soaking time. Finally, the heat efficiency was evaluated during 8 years of project life.
Simulation results show that dividing the perforation into injection and production intervals will reduce CSOR 30% and this requires shorter soaking time compared to that of conventional processes. Furthermore, if the distance between injection and production interval is longer the production will be better. However, this gap is limited by reservoir thickness.
This study illustrates a comprehensive-Integrated approach to identify the potential locations for future development in a sector area of a giant carbonate mature oil reservoir. The approach uses various data from several sources including reservoir surveillance, production performance, geological interpretation and numerical simulation and cohesively combines them to yield an informed decision to assess field development and management. The study area is under peripheral waterflood for more than fifty years and dominated by heterogeneity related to fracture corridors, high permeable zone, and reservoir zonation. These features leads to a preferential and uneven propagation of water flow which results in un-swept oil bearing spots using the existing wells lay-out and configuration.
The reservoir management team has developed an integrated workflow to address these challenges by using several reservoir engineering methods and models including Water Encroachment, Reservoir Opportunity Index, Fractional Flow Calculation, Remaining Volumetric and Water Flow Paths. The designed workflow consists of creating derived attributes that describe these models and filter the sector area to define the sweet spots. The selection and prioritization of the defined sweet spots are supported by available reservoir surveillance and production data. However, the scarcity of reservoir surveillance and production data in some areas of the sector, motivated reservoir management team to stretch the limits by capitalizing on gas wells penetrating the shallower oil reservoirs. The open-hole logs of these wells recorded thicker oil column than the pre-estimated column using the existing surveillance data.
As a result of these efforts, a development plan was designed in order to ensure reserves depletion in the identified sweet spots by drilling new wells or sidetracking the existing wells. Despite the level of maturity, simulation forecasts indicate that the area of interest has lot of potential to sustain a high production rate.
Increasing efficiency and safety of drilling operations requires proactive planning and ability to make timely educated decisions. Evaluating operational experience and statistically organizing available drilling data provide valuable forecasting tools, which help to increase the rate of successful decisions. For this paper, drilling records from 54 recent wells drilled by Saudi Aramco exploration unit throughout 2009-2011 period, both offshore and onshore, were evaluated. Large volume of statistical data related to drilling fluid losses was systemized. Losses were tagged as partial and total losses for each well and hole size. Drilling fluid daily reports provided insight into volume and cost of losses for drilled hole sections. Fluid losses cost per foot and lost time cost per hour was calculated. Cost per foot of LCM and cost per foot of other fluid loss preventive techniques and technologies was estimated, as well. This data analyses led to the capability of benchmarking expected losses cost per foot against expected cost per foot of available fluid loss fighting or preventive materials and services. Obtained numbers provide straight forward decisive data to plan for cost effective solution using a decision flowchart. Available statistical and risk evaluation software adds to the decision process effectiveness. This paper does not cover all available or would be available loss prevention techniques and technologies. The discussed method was applied in real life, and aerated drilling fluid services are contracted for Saudi Aramco drilling operations.
Recognition of variations in borehole shape in real time drilling allows the drilling engineer to actuate appropriate counteractions to avoid costly failures, or to implement alterations in the drilling practices to optimize the shape of the borehole and thus improve the drilling efficiency.
Developing a high accurate ultrasonic caliper with a special design helps the drilling engineer not only to monitor the wellbore shape and profile but also detecting a kick in real time drilling.
The result of ultrasonic calipers measurement is a 4D image of the borehole, which helps the driller to make proper decisions such as reaming a critical zone, changing the flow rate to reduce erosion or modifying the string rotation speed to reduce vibrations and also detecting a kick when an influx enter to the borehole while drilling.
This paper reviews tests and experiments which have been performed by using high frequency ultrasonic caliper sensor in different drilling fluids and wellbore conditions. A fully automated test robot has been designed which allows vertical and lateral movement as well as rotation of a sensor head in an artificial wellbore for performing the test. Results show that, new design of the ultrasonic caliper increases the accuracy of the measurement by recording the sound velocity in downhole condition.
To simulate the kick condition, pressured air was injected while measuring borehole profile to simulate a kick situation. According to the results, with the special design of the tool it is possible to detect the kick while drilling as well as during wellbore diameter measurement procedure in the downhole condition.
Crude oil characterization is important prior to development of complex network of surface and subsurface facilities for oil and gas production. Fluid behavior change in multiple set of conditions could cause problems related to fluid flow, solid deposition, wax formation and fluid transportation. This change could pose additional risk with tough terrains and challenging environments and it could jeopardize the project cost economics too.
In this paper laboratory result of crude oil evaluation of Upper Assam Field, India is presented. The purpose of the present work was to examine the behavior of produced fluid with highlighting issues which could impact on safety, integrity, production capacity and operational support for the asset throughout project lifecycle. Strategies can then be developed to resolve those issues. Detailed carbon profile of crude oil and wax content, distribution of molecular weight were determined through simulated distillation (SIMDIS) using Perkin Elmer Gas Chromatograph hardware and software. Physical characterization such as density, pour point, water content, bound sand and water, KUOP, wax content was done using ASTM methods. Boiling point profile generated from the experiments was used to find crude oil type. Saturates, aromatics, resins and asphaltene (SARA) analysis was done using standard method to find asphaltene deposition potential. Normal and non-normal paraffinic content of wax is calculated using the “Wax Profiling” software from ControlChrom to find wax predominating characteristics. Tulsa University “WAX” software was used to predict wax appearance temperature at atmospheric pressure and temperature. Solid fraction isobar was generated using the software. The viscosity of the crude oil at different temperatures considering the pour point and different shear rates was measured using MV DIN Sensor system and M-5 measuring system of Haake viscometer.
An ongoing focus area for Saudi Aramco is the optimum field development and depletion of the mobile oil in the tar area, which is limited in extent and occurs mainly along of the periphery of the southeast flank of the field. Unlike many tar mats in other fields, the tar in this field is patchy and has a complex distribution in the reservoir. In addition, areal and vertical tar extensions reveal great variations along with the existence of fractures in the area which imposes difficulties on the reservoir characterization as well as predicting fluid flow behavior.
The objectives of this paper is to present an overview of the tar infected areas, reservoir performance, formation evaluation results, reservoir characterization and modeling workflow to formulate the development strategy. Various tools were utilized such as NMR log, flow-meters, POPI analysis, PVT analysis, Pressure Transient and core analysis to better understand the tar and optimize the development strategy. This paper also documents the results of a recently drilled evaluation well and the proposed horizontal sidetracks performances as actual case studies.