Pore volume compressibility is a critical parameter to evaluate the reservoir potential and recovery factor. It is ideally determined through uniaxial core measurements, but may also be inferred through conversion of hydrostatic core analysis to ‘effective' uniaxial values. Alternatively, determination of pore volume compressibility (PVC) through logs offers the option to devise an early PVC strategy for field development without extensive SCAL. While some successful siliciclastic case studies are available for log-based PVC estimation, little is established for similar techniques in carbonates due to its complex pore network. Devising a truly log based method that can serve equally well in carbonates is a challenge to the industry. This paper describes a new technique for log-based estimation of PVC.
The evaluation of dry frame bulk compressibility and matrix bulk compressibility are the basic pre-requisites for PVC determination in a rock poro-elastic model. Volumetric log analysis is utilized to determine relative components of complex matrix volumes and porosity. Hashin-Shtikman (HS) bounds are adopted to determine matrix elastic properties of a composite system. To determine the dry frame elastic properties, the present technique utilizes a Differential Effective Medium model and adopts the concept of effective aspect ratio that simulates the rock elastic behavior. It employs the assumption of constant rock shear compressibility under wet and dry conditions to predict dry rock behavior. In an iterative procedure, the approach predicts effective aspect ratio, dry frame bulk compressibility and in-situ pore volume compressibility for the each log depth. The shear compressibility input for DEM analysis is derived through sonic and density logs.
This technique is implemented in dolomite dominant complex carbonates in the south of the Sultanate of Oman. The model is validated in test wells where excellent match is observed between log-computed PVC and uniaxial core values. It is observed that pore volume compressibility is strongly dependent upon the effective aspect ratio and the porosity. This study delineates this relationship. For comparison, an inverse Gassmann's equation was used to determine dry bulk compressibility and found to highly underestimate pore compressibility.
Al-Shuwaikhat, Hisham I. (Saudi Aramco ) | Al-Mubarak, Yousef A. (Saudi Aramco) | Al-Khalaf, Ahmed A. (Saudi Aramco) | Khan, Rafaqat A. (Saudi Aramco) | Al-Shuwaier, Saud A. (Saudi Aramco) | Gazi, Mohammed A. (Saudi Aramco) | Gilani, SyedKhalid M. (Saudi Aramco)
Successful health, safety and environmental (HSE) management is critical to the oil and gas Industry as no one can put a price tag on human life. HSE performance and business success are interdependent to achieve organizational goals.
Saudi Aramco has created a corporate HSE management system for its organizations to address its own unique operating needs. Saudi Aramco also requested each organization to create its own HSE management systems based on the corporate HSE management system. The Southern Area Production Engineering Department (SAPED) at Saudi Aramco has developed a production engineering and operation HSE safety management system that addresses several safety items, such as risk assessment, operating standards, asset integrity, incident reporting, and emergency handling in 11 key elements. These elements are intended to provide clarity to SAPED personnel on the safety requirements and their roles and responsibilities.
The appearance of this management system is seen as a milestone event and the vision is perceived as the objective. The move to management systems in operational fields recognizes the need for accountability, measurement, hazard management, feedback and priority of resource allocation. The management system deals with valuable human resources and assets including employees, wells, facilities, equipment and vehicles. For effective communication of these processes, SAPED assigned an HSE advisor for each organization and an HSE coordinator for each division to ensure full HSE compliance and implementation to enhance the overall organization HSE performance.
SAPED has established systematic Key Performance Indicators (KPIs) to ensure meeting specific, measurable, applicable, realistic and time-bounded (SMART) objectives. This initiative has provided positive results, which include improved awareness of the SAPED HSE management system's expectations, improved understanding of SAPED HSE requirements, improved cooperation towards achieving the HSE goals and targets, and lowered accidents and incidents, which ultimately resulted in enhanced HSE performance. This paper outlines the processes, methodology and leading indicators analysis being used by SAPED for enhancing its HSE and KPIs performance through an effective HSE management system.
Recently, Saudi Aramco upstream activities in unconventional gas, and in particular tight gas sands, have been identified as a focus area. Integral to understanding the potential of tight gas as a resource, is an understanding of the petrophysical characterization of tight gas intervals. This paper presents a review of the petrophysical challenges in the evaluation of tight gas intervals encountered within an existing producing field producing from formation U. This formation can be highly variable and although it can be highly productive, in some areas the geology has produced poorer reservoir quality rock. Production from wells which penetrate these areas can exhibit "Tight Gas?? characteristics. Core and log data from existing fields are abundant and cover both good and poorer quality reservoir intervals. The factors which impact the evaluation of these "Tight Gas?? intervals, in this relatively well sampled environment, can be generalized to the evaluation of less well studied tight gas formations. The results of this review identify many areas where current techniques and tools fall short of providing an adequate characterization. In particular, the quantification of mineralogy and diagenesis is seen as important, as is the quantification of saturations and accurate measurement of micro-Darcy permeabilities. Areas where current techniques require improvement are highlighted and projects that are in progress to address these issues and improve the evaluation of tight gas are detailed. One area which is highlighted as holding potential is rock typing, which can categorize different types of tight gas interval based on clay content or mineralogy. Three wells have been selected for a fracturing exercise as a proof of concept to assess the production potential. The results of the fracturing exercise are presented relative to the petrophysical evaluation of these wells.
Stimulation of high temperature oil and gas wells with HCl could cause significant corrosion to tubular goods. Organic acids are viable alternatives to HCl. However, conventional wisdom teaches that organic acids do not spend to its full capacity due to CO2 in solution. This leads to reducing their carbonate dissolving capacity further. Another potential drawback of using organic acids is the precipitation of the salt of calcium and organic ligands. Consequently, the concentration of the organic acid has to be confined to prevent the precipitation. Due to the above reasons, along with their cost per mass of rock dissolved, organic acids often have limited use in well stimulations.
Recent thermodynamic modeling studies have shown that when an organic acid or a mixture of HCl and an organic acid reacts with calcite, a previously unrecognized reaction occurs. This reaction enhances the calcite's dissolving capacity by the organic acid. The model provided new insight into the reaction equilibrium between organic acids with calcite, and gave a better understanding of which chemical species plays the dominant role in driving the overall dissolution reaction. In the case of acetic acid reacting with calcite, the model found that a chemical species, ca-monoacetate (Ca(CH3HCOO)+), exists because of the association of acetate and calcium ions. This species cannot be ignored. When quantitatively concentrated, it results in higher acetic acid dissolving capacity. Furthermore, mixing acetic acid with HCl can increase the conversion of acetic acid by the same calcium and acetate ion association and lead to more complete spending of acetic acid. The objective of this paper is to present the evidence of the existence of calcium monoacetate through experimental studies using Raman spectroscopy. Results showed that ca-monoacetate does exist during acetic acid dissolving of calcium carbonate. However, quantitative match between the experimental data and thermodynamic model prediction remains uncertain.
Caili, Dai (China University of Petroleum) | Qing, You (Peking University and China University) | Long, He (Northwest Oilfield of SINOPEC) | Qin, Guowei (Daqing Oilfield of CNPC) | Ping, Wang (China University of Petroleum) | Feng, Decheng (China University of Petroleum) | Fulin, Zhao (China University of Petroleum)
Tahe oilfield in China belongs to fractured-vuggy carbonate reservoir with high temperature (100~130 celsius degree) and high salinity (two hundred thousand mg/L containing ten thousands mg/L of Ca2+ and Mg2+). After exploration for many years, the bottom water cones through fractures and vugs into production wells and then oil production declines obviously. In order to solve this problem above, a new inorganic composite blocking agent is proposed and developed in this paper. This new blocking agent is composed of superfine cement, strengthening agent, density adjusting agent, bridging agent, suspension dispersing agent, retardant and drag reducer. By adjusting the different proportions of components to make sure the density of this new blocking agent is in 1.00~1.10g/cm3 between oil (0.80~0.98g/cm3) and water (1.14g/cm3) which can build up packer existing in water-oil transition zone to control bottom water coning caused by gravity segregation resulting from density difference. Then the agent could expand sweep volume of bottom water and enhance oil recovery. This new blocking agent had been applied in one production well in Mar 2009, by Jul 2010, the accumulated oil increment is 1753.31t, the water cut decreased from 99.23% to 91.64% and the input-output ratio is up to 1:2.0. The success of field test confirmed that this new blocking agent is quite suitable for controlling bottom water coning and has a broad application prospect.
Ali, Mohammad A.J. (Kuwait Institute for Scientific Research) | Abeer, Al-Farhan A. (Kuwait Institute for Scientific Research) | Ali, Al-Haddad A. (Kuwait Institute for Scientific Research) | Suhaib, Al-Kholosy A. (Kuwait Institute for Scientific Research)
Reinjection of produced water is of increasing importance in the oilindustry as water production continues to increase worldwide. It provides anenvironmentally acceptable solution to the disposal of produced water, andcontributes to pressure maintenance. The performance of the injection wells andthe distribution of the injected water are strongly influenced by water qualityand the build-up of formation impairment around the wellbore.
Solid particles and small oil droplets present in the injected water canblock the reservoir pores and cause rapid and severe permeability decline.Total removal of solids and oil may not be economically feasible or practicallypossible. Therefore, to minimize or slow the rate of impairment, it isimportant to understand the relationship between the impairment mechanism andwater quality parameters, such as the total suspended solids and oildroplet.
This experimental study highlights the importance of water quality for thepurpose of water injection. An online particle size analyzer was used tomeasure particle size distribution and coalesces in the injected water.Different concentrations of suspended solid, oil droplet, water salinity, andoil viscosity were used in this study. The effect of suspended solids on thestability of oil-in-water emulsion was investigated. Finally, coreflood systemwas used to measure permeability decline during water injection containingsuspended particle.
The results showed that increasing suspended solid concentration did notaffect particle coalesce, but increasing oil concentration resulted in anincrease of oil droplets coalesces. However, when a combination of solidparticles and oil droplets were suspended in water, newly solid-oil attachmentparticles were formed. Increasing water salinity did not affect solid-solidcoalesce, but formed smaller oil droplets. Higher oil viscosity generatedrelatively in larger oil droplets than lower viscosity oil. Visual observationof emulsion containing suspended solids and oil droplets showed more stabilizedemulsion with higher salinity water than at lower salinity water. However,weaker emulsion was seen when high oil viscosity concentration was used.Finally, permeability reduction of core samples caused by oil droplets alonewas insignificant, but higher damage was seen by suspended solids, and severedamage was observed with combined solid and oil droplets.
Rubber or elastomeric seals are flexible polymers used in a variety of applications in many industries and have become more widely used in oilfield equipment as polymer technology has advanced. The seals are used in many oilfield applications and can be damaged during a rapid decrease of pressure after being exposed to environments containing gas. This phenomenon is known as explosive decompression (ED) or rapid gas decompression (RGD).
RGD damage can be manifested as splits, cracks, or bubbles in the seals, depending on the rubber type, length of exposure to the gas, and the rate of pressure decrease. Damage caused to a seal by RGD can range in severity from a slight weakening of the physical properties of the rubber to a catastrophic failure of the integrity of the seal. Both surface operations and downhole conditions are capable of causing RGD, which, can result in failure of the equipment using the seals.
This paper discusses tests performed on various elastomeric samples, including swellable rubber, to determine the effects that RGD will have on the seals under varying conditions. The tests exposed each sample to a range of pressure drops and gas exposure times. The samples were analyzed after each test for physical changes and signs of RGD damage. The purpose of mapping the effects of RGD on multiple samples and the various conditions to which the seals were subjected was to develop a better understanding of the conditions leading to RGD damage and to identify operations at risk for causing RGD damage to elastomeric seals. The testing and results are further discussed in this paper.
With the focus on continuous drilling optimization, a collaborative effort was implemented to analyze and assess drilling challenges encountered while drilling extended horizontal wells in the Khurais field in Saudi Arabia. The primary requirement was to enhance the efficiency of conventional downhole motor directional drilling systems in the challenging horizontal reservoir section.
The Khurais field is located in a remote area in the central part of Saudi Arabia approximately 200 km from the Saudi capital Riyadh, and 300 km from the Eastern port city of Dammam. The producer wells are drilled in the middle of the field and the water injector wells are drilled close to the field boundaries.
An average of 12 rigs worked simultaneously throughout the duration of the project to drill and complete the required increment wells. The horizontal wells are comprised of the producers, trilateral producers and power water injectors. The wells were drilled to an averaged measured depth of 14,000 ft, with an average of 6,500 ft of open hole section across the reservoir. The 6??? horizontal hole section is particularly challenging and is drilled with steerable mud motors with the assistance of real time geosteering and logging while drilling (LWD) tools to maintain the horizontal open hole section of the well close to the top of the reservoir within a window of 3 ft.
The fracture intervals coupled with high permeability makes the drilling of this section particularly challenging, as mud losses are frequently encountered in this section. The main difficulties to improve the efficiency of the directional drilling process were high drag and differential sticking.
To overcome the challenges mentioned above, the drilling team utilized a new sliding technology that interacts with the drilling rig top drive to break the static friction improving the weight transfer to the bit, and thereby increase the rate of penetration (ROP). Through the virtual elimination of differential sticking and reduction of buckling problems, this system smoothly helps to deliver weight down to the bit. Additional benefits of this innovative technology are the prevention of stalling of the mud-motor, steady orientation of tool face and easier steering.
The authors will describe the innovative system utilized to improve the ROP during the sliding process by almost 50% and will present real cases supported by field data. They will also illustrate the importance of post-actions review and rig crew training in the achievement of record ROP in sliding mode. Historical cases will be presented and the benefits of the application of this technology in these wells will be explained.
Water, CO2, and steam flooding in oil wells are common today as many of the premium reservoirs are becoming significantly more difficult to efficiently produce. Much of the technology for optimizing the recovery in these assets revolves around well placement and production controls. When early flood-front breakthrough occurs, the options for improved asset economics are generally limited to near-wellbore controls to minimize the costs of producing, separating, and disposal of nonhydrocarbon production. Often, these controls have short-term effectiveness, and intervals or wells are prematurely abandoned. Altering flood fronts deep in the reservoir will offer much greater effect and longer-lasting control of nonhydrocarbon production. Successful alteration of the sweep pattern deep in the reservoir yields better sweep efficiency, lower operating costs and higher ultimate recovery.
This paper explores the benefits of well completions that incorporate a combination of near-wellbore and deep reservoir controls to modify the fluid-flow pattern when production coincides with an active water flood. By using numerical simulation of various completion methodologies with and without these controls, the benefits will become apparent. Optimization of these controls for a given completion will be illustrated for a single producer horizontal with vertical injector and for a producer pair of horizontals with a horizontal injector.
The large permeability contrast between fractures and matrix in highly fractured carbonate reservoirs has been a hindrance to the efficient recovery of the oil from the matrix. Gas oil gravity drainage (GOGD) has been the most appealing option to date. However it is a slow process. Cyclic Pressure Pumping (CPP) is proposed which has the potential of increasing the rate of recovery over GOGD under certain conditions. CPP utilises the fact that due to the much lower permeability in the matrix, the matrix pressure lags behind the fracture pressure during a rapid pressure change. A sudden drop in pressure in the fractures results in expansion of fluids in the adjoining matrix which are discharged into the fracture system. The fluids in the fracture system can then be produced. The reservoir can be re-pressurised by gas injection and depressurised by producing the fluids in an alternate manner.
This process originally called batch gas cycling was suggested in the 50s for improving recovery in non-homogeneous reservoirs over conventional gas flooding. It was tried successfully in a small field in the late 50s. Laboratory experiments in the 70s on low-permeability matrix in contact with high-permeability fractures indicated the effectiveness of the process.
The process was re-discovered during reservoir production optimisation simulation studies in a heavy oil steam injection project in Oman and will be applied to minimise oil loss during steam plant shut downs. Early field observations support the process. The paper presents a study of the process using both dual permeability and single porosity simulation modeling. It also highlights the conditions which are favorable to the process as well as certain practical problems that could be encountered in implementing it.