The advent of digital oil field technology initiated a new era of real-time data acquisition, which facilitated continuous field monitoring and swift intervention. Yesterdays’ or last hour’s real-time data is not “real-time” but can be classified as intelligent field data. Raw intelligent field data is usually recorded and stored in second or minute intervals and the size of the data has been continuously increasing. Consequently, the added value of the intelligent field data outweighed the challenges in the storage, validation and summarization of this huge amount of data. While reservoir engineers often struggle with historical well data that are limited in nature, and are measured at different time intervals, the continuous and synchronized data stream emerging from the intelligent field provides unique opportunities to improve the history matching process of reservoir simulation models.
In this paper, we present the data utilization and the workflows adopted to integrate these data into reservoir simulation modeling. The workflow is to manage data quality, consistency, conversion and reconciliation with allocation data. Additional challenges are in selection of intelligent field data to match, and on simulator reported pressure and time stepping. Continuous and synchronized data streaming in real-time means that data is available to the engineer almost instantly or within a short time frame from acquisition. The wealth of data enables the simulation engineer to appropriately diagnose and account for critical reservoir phenomena such as well interference and subsurface well responses to surface well actions. Successful integration of intelligent field data into reservoir simulation significantly enhances the quality and predictability of our models. This builds on the success of our high resolution geological models that attempt to capture all the spatial heterogeneities. Similarly, high resolution temporal data attempts to capture all dynamic actions and reactions within the reservoir to further improve the reservoir simulation models.
Acid proved an efficient near wellbore skin damage removing agent in carbonate production and injection wells. Nevertheless, improving acid stimulation design is a continuous need in oil industry. Formation analysis logs for some of South Ghawar power water injectors have shown a significant amount of residual oil dominating the open hole interval. This phenomenon results in wells transmissibility reduction, which reflects negatively on injection rate.
A unique type of de-paraffin organic solvent was recently introduced to acid treatment design in South Ghawar PWIs to tackle injection impediment caused by high irreducible oil saturation. This solvent demonstrated a great capability in removing and flushing off residual oil, wax and asphaltene deposits in the reservoir matrix. Adding this solvent to pre-flush the rock enhanced the main acid treatment propagation into the reservoir, as well as water injection afterwards.
This paper presents the influence of the organic solvent on some of South Ghawar horizontal and vertical PWIs performance after acid treatment. It will also compare the injectivity of wells — with similar parameters and properties — that were acidized without adding this organic solvent in treatment. Differences in results due to modification of this product will also be discussed.
Oil compressibility above bubble point pressure is important in reservoir simulation, material balance calculations, design of high-pressure surface-equipment and the interpretation of well test analysis. Accurate calculation of oil compressibility is very important for reservoir evaluation.
The oil compressibility above bubble point pressure increases with increasing temperature and decreasing pressure, therefore, curves at the same pressure and different temperatures should not cross each other.
The conventional method of obtaining oil compressibility is from individual temperature measurement of pressure-volume data of constant composition expansion test. The oil compressibility determination involves pressure-volume function and its derivative at each temperature. This individual estimation with derivative calculation makes oil compressibility evaluation very sensitive to small derivative change that may lead to an invalid and non physical behavior of curve crossing.
This paper presents a special constrained multiple linear regression optimizations that ensures non-crossing of oil compressibility curves above bubble point pressure for multiple temperatures.
There is a need worldwide to diversify the energy resources and rely on unconventional energy sources to prolong the oil reserves, attract hi-tech manufacturers, support knowledge based economy, and reduce carbon foot print. The current state of knowledge is confined in isolated research and development related to various renewable energy technologies such as passive energy, wind, Solar, biofuels, hydrothermal, and energy conservations. However, there are limited attempts, to integrate many of the aforementioned technologies in one place and monitor the impact of the integration on their efficiency and feasibility; as well as quantify the impact of other technologies related to energy and water conservation. The Integrated Model for Sustainable Development (IMSD) is a conceptual model that provides a unique conceptualization approach to study the impact of integrating individual technologies on a holistic energy and water systems. Additionally, blooming population increase worldwide put lots of strain on already scarce water resources. Almost 25% of energy produced is used for water extraction, treatment and delivery. Therefore, it is important for the 21 century technologies to address the energy-water-environment nexus, which result in better management of resources while maintaining clean environment for future generations. The IMSD is an innovative approach that provides a comprehensive platform that combines technology development, economics, environmental impact assessment, decision support and human capacity development in one platform.
Well Completions design is continuously evolving to meet increasing requirements of down hole monitoring and control. The design of well completion has become more sophisticated as these requirements increase. Nowadays in the industry, it is rare to find a well completion that does not have some type of down hole sensor or inflow control. This paper presents overview of six different well completions designed to meet different reservoir and production requirements. Each of these design are integrations of existing and new technologies. The technologies presented in the paper range from inflow control devices and open hole packers placed in the reservoir section, multilateral junction systems, through permanent down hole sensors, surface controlled down hole valves and electric submersible pumps in the production tubing. The paper also discusses briefly the integration of the down hole equipment with surface control panels and SCADA communication systems. Different well types like oil producers, water injectors and artificial lift wells are discussed.
Reservoir monitoring is an important aspect of prudent reservoir management to sustain productivity and achieve higher hydrocarbon recoveries. Monitoring is a process that comes in various forms, such as that of flood front advancement and reservoir saturation changes and quantification. Designing and implementing an effective monitoring program to track fluid advancement and quantify remaining oil saturation is a reservoir management best practice that ensures optimum sweep is achieved; and so is crucial for all fields, regardless of their state of maturity. The necessity for such programs becomes more critical as fields mature.
Reservoir saturation monitoring programs are usually faced with several challenges, including: mixed and low fluid salinity, tool limitations, borehole conditions and reservoir heterogeneity. Overcoming these challenges requires comprehensive programs that encompass adoption and integration of various derived saturation techniques.
This paper will discuss a reservoir monitoring program of a large carbonate field that has produced continuously for several decades. The monitoring program includes “key monitoring wells” in addition to drilling new evaluation wells that are strategically selected and are mostly located in well flooded areas. Time-lapse production and fit for purpose saturation logs are run in the existing wells, while extensive in situ measurements of fluid saturation are collected in the case of the new wells, to monitor saturation changes and track the movement of fluids.
The paper will also discuss the various methodologies adopted to address the aforementioned challenges. It will illustrate how the monitoring program has aided in tracking fluid movement, quantitatively determining fluid saturations and assessing sweep efficiency (Ed, Ev and Ea). In addition, the paper will show how the collected information was a catalyst in identifying sweet spots in flooded regions, and therefore guiding development activities for maximizing hydrocarbon recovery, especially from mature areas.
Using solid particulate additives is becoming difficult because of strict health, safety, and environmental (HSE) concerns and green operation initiatives taken by operators. When solid particulates are used as additives for downhole treatments, they are generally batch-mixed into the gelled fluid as long as the viscosity of the fluid is sufficient to prevent settling of the particles. It is possible that solid particles could settle and block the blending equipment; hence, an additional blender is required at location to mix such solid additives so that the main or primary blender remains functional throughout the job for subsequent mixing of other treatment fluids. Using the additional blender requires additional logistics, man power, and associated costs to the operator. Therefore, it is usually recommended to use liquid additives in the field to help avoid problems associated with using solids and related additional equipment issues.
This paper describes the systematic approach used for the development of a non-aqueous suspension fluid for suspending varied-sized (8 to 40 mesh; ~2400 to ~400 µ particles of a particulate diverter with a specific gravity of 1.29 g/cm3. The developed suspension is stable at ambient temperatures for more than 30 days. It remains free flowing for more than 30 days, even at 40°F, and the solid particles do not settle, even at slightly higher temperatures, such as 100°F. The chemical score index (CSI) of the formulation is 120, which shows that the suspension is environmentally acceptable. Performance of the suspension was evaluated through core flow experiments with brown sandstone core samples, which indicated that the fluid containing the newly developed suspension of the diverter particles did not cause formation damage to the samples used.
Recently the low salinity water flooding has been introduced as an effective enhanced oil recovery method in sandstone and carbonate reservoirs. The recovery mechanism using low salinity water injection is still debatable. The suggested mechanisms are: wettability alteration, interfacial tension reduction, and rock dissolution. In this paper we will introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low salinity water injection without treating sea water. The new chemical EOR fluid can be used at low concentrations and can be added to the raw sea water without treatment or softening. Low salinity water was proved to cause damage to the reservoir because of the calcium sulfate scale formation during the flooding process. These chemicals are chelating agents at high pH value such as EDTA and HEDTA.
Coreflood experiments and zeta potential measurements were performed using EDTA and HEDA chelating agents added to the sea water and injected into Berea sandstone and Indiana limestone cores of 6 in. length and 1.5 in. diameter. The coreflooding experiments were performed at 100oC and high pressure. The newly introduced EOR method does not cause sulfate precipitation and the core permeability was not affected. The coreflooding effluent was analyzed for cations using the ICP to explain the recovery mechanism. The effect of iron minerals on the rock surface charge will be investigated through the measurements of zeta potential for different rocks containing different iron minerals.
The oil recovery increase in both sandstone and carbonate cores was up to 23% of the initial oil in place using the new fluid system. The rock dissolution, interfacial tension (IFT) reduction, and wettability alteration were the recovery mechanism in order. The IFT reduction was due to the high pH of the newly introduced fluid. The existence of iron minerals in sandstone rocks increase the positive values of zeta potential and this will change the rock towards more oil wet. Adding EDTA and HEDTA chelating agents at high pH to the sandstone rocks containing iron changed zeta potential to be negative in which changing the rock towards more water wet.
Gas-condensate fields producing under natural depletion are often faced with the challenge of finding adequate, long term and cost effective solutions to energize the pressure decline in the old gas wells after long years of production and drainage depletion. The most common practice is re-entry operation utilizing a workover rig to target a new section in the reservoir or implement a new completion to conduct an advanced stimulation technique. These options are expensive and not the most effective as there will be a lengthy idle time until the workover is conducted. The problem is worsened as reservoir pressure falls below dew point which could cause liquid loading compounded by water production issues in the wellbore.
The primary objective is to boost the wellhead pressure to overcome the back pressure imposed by the downstream main gas flow system. Other than an expensive option of a workover job with a rig, a boosting system can be acquired in such cases to maintain production or to prolong the production life of the fields and increase the total rate of hydrocarbon recovery.
The innovative use of Velocity Spool (VS), commercially known as Surface Jet Pump (SJP), technology is one of the simplest and most cost effective ways to boost low pressure and revive dead wells. The SJP (or VS) system is a device that has no rotating parts which utilises pressure energy from high pressure well (or group of wells) to help low pressure well (or group of wells) flow against high pressure upstream facilities without the need for compression. Furthermore, the Velocity Spool can defer or replace the eventual use of conventional technology, such as compressors. It can also save considerable capital and operating costs associated with re-entries.
The SJP system has been successfully applied worldwide onshore/offshore to generate incremental production and optimise production process. However, the application discussed in this paper under the applied conditions is the first of its kind worldwide. This paper provides details of the recent novel SJP (VS) system applications in Saudi Aramco onshore gas fields. The implementation involved installation of the VS on ten different Low Pressure (LP) gas wells to utilize the strong stream HP well(s) that were drilled recently or producing from a more prolific reservoir section.
Recent field examples of this technology from Saudi Arabia are covered in this paper. The paper also addresses the economic aspects of the technology applications by giving an indication of the payback periods that can be achieved from the added revenue or from cost savings. Field applications have shown that the recovery of the capital spent in installing SJP (VS) systems is generally achieved within a few weeks to a few months.
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.