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.
A new robust metaheuristic optimization method, namely modified cuckoo search (MCS), is presented in this paper. MCS is inspired by breeding behavior of cuckoo birds and combined with Levy flight approach to efficiently search for optimal solutions. MCS is coupled with a filtering technique to provide the ability to handle nonlinear constraints. The filter-based MCS is efficient insofar as it provides a bias toward exploration during early generations allowing for global search and then shifts that bias toward exploitation at final generations allowing to search promising areas of the solution. This helps in finding feasible solutions at earlier search stages and consequently improves convergence rate.
Two example cases involving two-dimensional synthetic reservoir models are presented. The first case compares the performance of MCS to that of genetic algorithm (GA) to maximize oil recovery by optimizing the location of four injection wells. It is shown that MCS outperforms GA in terms of the optimal solution as well as the rate of convergence. The second case entails the use of filter-based MCS to maximize NPV under maximum water cut constraint at the production well. The results indicate the superior performance of the filter-based MCS as it was able to quickly find feasible solutions even though all previous initial solutions were infeasible. The incorporation of filtering technique allows to assess the sensitivity of the objective function to the constraint violation. This provides additional insights that can lead to better future planning.
A low permeability gas condensate carbonate reservoir in the Khuff formation is one of the main producing reservoirs in Field-A in Saudi Arabia. This early Triassic carbonate reservoir, first discovered in 1980, holds significant gas-in-place but is a blend of conventional and tight intervals. Vertical completions, horizontal wells with maximum reservoir contacts, and acid stimulation (matrix and fracturing) are some of the current practices to effectively develop the reserves from the tighter intervals.
In late 2009, the open hole horizontal multistage fracturing (OHMSF) completion assemblies were deployed in several horizontal wells in the tight gas area with the goal of achieving multiple independent hydraulic fractures, greater acid stimulation efficiency, and thereby enhancing well productivity. The OHMSF systems enable the open hole section to be divided into segments based on the reservoir’s petrophysical and flow properties by the use of mechanical open hole isolation packers and customizing the stimulation treatment for each segment via fracturing ports that are installed in between the packer assemblies.
Since the inception of OHMFS, many wells were treated and varying results were obtained. The results are dependent not only on reservoir quality and development, but also on the placement of the fracturing ports, number of fracture stages conducted, and fracturing strategy.
This paper provides insight into the planning, challenges encountered, sensitivity analysis and performance analysis of the OHMSF wells in comparison with non-OHMSF wells. It also details several case histories and highlights the results as well as lessons learned that can be applied in the future to improve the recovery.
The successful production of heavy oil (typically defined as oil with an API gravity of less than 20) depends on several reservoir properties such as porosity, permeability and reservoir pressure, but it is the in-situ oil viscosity that dictates the oil mobility and production approach required, and ultimately the economic viability of the project. For this reason, the possibility of estimating the hydrocarbon viscosity from logs, thereby providing a continuous record of the fluid properties along the reservoir is of great value.
Fluid viscosity has a strong effect on nuclear magnetic resonance (NMR) logs, including the NMR relaxation rate (T1 and T2 distributions), diffusivity, and signal amplitude (NMR porosity) measurements. These effects can be exploited to derive correlations to viscosity. Depending on the viscosity range, NMR standalone methods can be used, typically for 1 to 100 cp. For higher viscosities, a volumetric approach is required, combining the NMR data with other logs to develop specific correlations for particular reservoirs and oil types. These correlations are not universally applicable, and must be customized before being applied to a different environment.
Several techniques were compared to estimate oil viscosity in a shallow Miocene reservoir. The formation is characterized by very complex mineralogy, high porosity, and slightly freshwater salinity. This complicates the volumetric approach, which requires an accurate total porosity and oil volume estimation. We discuss how elemental spectroscopy and dielectric logs help to reduce the uncertainty in the viscosity estimation. The merits and applicability of NMR-only techniques in this complex environment were also explored. The log-based viscosity correlations were calibrated with in-situ and laboratory fluid sample viscosity measurements. The model will be used to predict viscosities prior to performing well tests in subsequent wells.
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.
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.
Almubarak, Tariq (Saudi Aramco) | Bataweel, Mohammed (Saudi Aramco) | Rafie, Majid (Saudi Aramco) | Said, Rifat (Saudi Aramco) | Al-Ibrahim, Hussain (Saudi Aramco) | Al-Hajri, Mohammad (Saudi Aramco) | Osode, Peter (Saudi Aramco) | Al-Rustum, Abdullah (Saudi Aramco) | Aldajani, Omar (Saudi Aramco)
Multistage acid fracture treatments are utilized in low-permeability carbonate reservoirs (permeability <10 md) to stimulate the formation by creating highly conductive fractures in the formation and bypassing near wellbore damage. The fracture is generated at high pressures that are required to break the rock open while using a viscous pad. The fracture is then kept open by adding gelled or emulsified acid to create uneven etches on the surface of the fracture.
Pre-job acid fracturing treatment fluids' reaction and compatibility analysis in the laboratory are crucial as the operational success is highly dependent on its chemicals’ reactions. The key problem with acid fracturing treatments is the difficulty in appraising the actual downhole reactions and performance of the treatment chemicals within the heterogeneous rock. This problem can be resolved when flow back fluids and the chemical ions are analyzed to understand the reactions that occurred down hole. Also, since acid fracture treatments require pumping large volume of fluids, flowing back the entire fluids becomes a challenge due to the low reservoir permeability and the associated reservoir rock capillary pressure effects.
This paper will discuss the pre-fracture treatment evaluation based on laboratory experiments - core flood, rock dissolving capacity, and fluid compatibility in addition to comparing the expected chemical ion returns with the actual ions observed in the flow-back fluids.
The results of this flow-back fluid analysis showed a recovery of 17% of the chemicals pumped during the treatment with a stabilized production rate of 3 MBOPD. Further water analysis indicated the presence of 25-30% formation water while the critical ions analyzed showed the effectiveness of the corrosion inhibitor package, acid system dissolving capacity, and crosslinker fluid recovery. It is expected that this paper will provide a learning process for optimizing future multistage acid fracture treatment in Saudi Arabia.
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.
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.
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.