Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | BaTaweel, Mohammed (Saudi Aramco) | Elktatany, Salaheldin (King Fahd University of Petroleum & Minerals)
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.
In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.
The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
Alfarge, Dheiaa (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Almansour, Abdullah (King Abdulaziz City for Science and Technology)
Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in water production after some oil and gas reservoirs being hydraulically-fractured. Moreover, the physical reasoning behind the variations in DPR performance for different scenarios has been extensively discussed.
The results explored that DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number<0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number >10), the effective period of DPR treatment was short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir is a good candidate for DPR treatment as compared when the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally has a significant role to mitigate water production. Finally, the dimensions of treated fracture are the key components to get a successful DPR-treatment in fractured reservoirs.
Water production is considered one of the most dominant problems in matured oil and gas wells. Difficulty of this problem comes from the significant cost associated with the water production. This cost is resulted from separating, treating, and disposing of produced water which is approximately estimated as $50 billion annually (Hill et al., 2012). Different solutions were suggested to control the excessive water production according to the sources and reasons of the produced water in hydrocarbon reservoirs. In some situations, all the suggested methods to control water production would not be effective except DPR (Mennella et al., 2001). Therefore, DPR treatment is one of the attractive methods to mitigate water production through production wells, not only by its low cost, but also by its easiness to be performed. The DPR property is considered very important in production wells when the mechanical isolation is very difficult to perform (Liang et al., 1993). And, there are some situations which need DPR treatments to be performed; otherwise the well would be abandoned (Mennella et al., 2001).
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
High and efficient deliverability of stimulated reservoir volume through a hydraulic fracturing treatment relies on three segments: fluid flow from matrix to the interface between fracture and matrix media, fluid-rock interaction at the fracture-matrix interface, and conductivity of fracture network. Thus, fluids and salt exchange between matrix and fracture network are critical and worth detailed investigation. Moreover, matrix imbibition as an important EOR mechanism has been extensively studied but the focus was mostly given to capillary effect. However, for shale, due to the pore structure and clay content, some physico- or electro-chemical forces at molecular level cannot be overlooked anymore, such as osmosis.
A multi-mechanistic numerical shale matrix imbibition model is developed. The model takes into account dynamic water movement caused by capillary pressure and osmotic pressure as a function of water saturation and salt concentration, respectively. The rock matrix is considered as the mixture of two different components, one with small nano/micro-pores and semi-permeable membrane property and the other having larger meso-pores. The model properly simulates water and salt transportation occurring across the matrix-fracture network contact surface driven by capillarity, osmosis, and salt diffusion. To honor the physics, the salt/ions concentration equation differs from previous work by removing the osmosis component and a new membrane efficiency coefficient is defined and properly incorporated in the model.
Spontaneous imbibition test results were used for matching and validation purposes. The simulation results well explained laboratory high-salinity water imbibition curve, which can be divided into three processes. Initially, a capillary driven imbibition sucks high salt-concentration water into matrix near the matrix-fracture contact surface. However, due to the significant salinity contrast between imbibed fluids and in-situ matrix salinity, a drainage process can be induced. Eventually, as salinity difference decreases and osmosis is weakening, final imbibition stage starts. This model provides a basis for laboratory measurements interpretation and brings some insights to reveal the underlying mechanisms for field post-frac flow-back behavior.
This paper discusses successful damage remediation performed in more than 10 wells in a mature oil field producing under a developed waterflooding project in Colombia. The primary damage mechanism observed is associated with a detriment to production related to reduced relative permeability caused by wettability preferences.
A chemical treatment was proposed that consisted of crude oil with efficient and effective surface active additives, such as microemulsions (MEs) and/or formation mobility modifiers (FMMs) and associative polymers (APs) for a proper diversion. The treatment was proposed as an effective method to restore near-wellbore (NWB) permeability in or through the damaged zone in the formation, resulting in production recovery. All matrix-stimulation treatments were conducted rigless by means of an annulus without affecting the artificial lift method and resulted in a significant time and cost savings.
Laboratory data confirmed the ability of the MEs and FMMs to modify interfacial tensions (IFTs) and contact angles. These materials helped promote a change in the degree of wetting of the system, which is dependent on the adhesion tension (the product of the IFT by the cosine of the contact angle). During well treatments, surface pressure spikes during the diversion stages were associated with the arrival of the APs at the perforations and were clearly observed during the development of the treatments, revealing that effective diversion was achieved. Finally, post-stimulation treatment data have shown positive results, confirming the effectiveness of combining these technologies.
This paper discusses how the synergy of using surface active additives with diversion technologies can yield productivity increase in mature oil reservoirs and improve the level of sustainability of current field production.
Al-dahlan, Mohammed N (Saudi Aramco PE&D) | Al-Obied, Marwa Ahmad (Saudi Aramco PE&D) | MARSHAD, KHALID Mohammad (Saudi Aramco PE&D) | Sahman, Faisal M (Saudi Aramco) | Al-Yami, Ibrahim Saleh (Saudi Aramco PE&D) | AlHajri, Abdullah (Saudi Aramco PE&D)
Description of the material
This paper presents the results of the study conducted on HCl-Replacement-Acid (HRA), a synthetic HCl replacement chemical, with health hazard rating of one and dissolving power similar to HCl. An extensive experimental scheme including: thermal stability, dissolving power, acidity, compatibility, corrosion rate & inhibition and coreflooding on carbonate formation core plugs was conducted.
Acid treatments of carbonate formations are usually carried out using mineral acid (HCl), organic acids (formic and acetic), mixed acids (HCl-formic, HCl-acetic), and retarded acids. The major challenges when using these acids are their high corrosion rate, fast reaction rate and health hazard. The improvement in corrosion inhibitors makes the use of strong acid as high as 28 wt% HCl possible. The acid reaction rate can be controlled by decreasing diffusion rate of hydronium ions (H+) to the rock surface where reactions take place by increasing acid viscosity using gelling agent or emulsifying acid droplet in a hydrocarbons liquid, acid-in-diesel emulsion. While the issues of stimulation acids reaction and corrosion rates are relatively controlled, these acids health hazard rating of 3 by the National Fire Protection Association (NFPA) is major concern. A health hazard rating of 3 is defined as an extreme danger where short exposure could cause serious injury
Results, Observations, and Conclusions
Based on this study results, the HRA was found to be thermally stable with similar dissolving power to 15 wt% HCl and lower corrosion rate. In addition, the HRA developed a breakthrough on core plugs with average pore volume (PV) of 2.7 and approximately 3 folds increase in permeability.
Significance of subject matter
An acid replacement chemical that has no or minimum health hazard rating while still has the ability to dissolve carbonate rock would be a major forward step in stimulation technology.
In contrast to near-wellbore conformance control applications, polymer gels are applied in injector wells for reservoir scale applications for in-depth fluid diversion (IFD). Novel gel systems include weak gels, sequential injection for in-situ gels, colloidal dispersion gels, preformed gels, and microgels. The objective of an IFD process is to modify the prevailing reservoir inflow profile by gel treating the reservoir to significantly reduce effective permeability of high permeability zones that would otherwise dominate the water uptake. The weak gels or gel particles are treated as a flowing fluid and are custom-made for reservoirs with fractures or high permeability zones. The very weak gels form near the wellbore region, but continue to propagate into the reservoir. The gels eventually stop propagating deeper into reservoir due to the variation in pressure gradients and pore structures. The subsequent injection of fluids, water or chemical solutions, will redirect predominate flow paths to unswept reservoir zones, which improves oil sweep efficiency by waterflood (or chemical flood); thus, leading to enhanced oil recovery. The technology presents distinctive advantages to high-salinity and high-temperature reservoirs as compared to polymer flooding due to stability of cross-linked gel structures.
This paper presents a state-of-the-art review of IFD technologies including weak gels, sequential injection for in-situ gels, colloidal dispersion gels (CDG), microgels, and preformed particle gels (PPG). Moreover, a solution to the challenges of IFD applications in high-salinity and high-temperature reservoirs is presented.
Bajunaid, Hani Ahmed (Al-Khafji Joint Operations) | Moawad, Taha Mousrafa (Al-Khafji Joint Operations) | Al-dhafeeri, Abdullah M (Al-Khafji Joint Operations) | Abd Elfattah, Mahmoud Mohamed (Schlumberger) | Mohammed, Tawakol I. (Al-Khafji Joint Operations)
Khafji offshore field, located in the Arabian Gulf, contains an unconsolidated sand reservoir subdivided into two, upper and lower reservoirs. Upper sandstone reservoir has relatively low reservoir pressure utilizing gas lift to help wells achieve production target rate. The main obstacle in upper reservoir is water encroachment due to unfavorably high-water mobility compared to oil; which presents a reservoir management challenge in the form of curbing water production linked to relatively high-permeability sandstone reservoir. In upper reservoir, water encroachment is dominated by active edge-water drive and it has irregular water-front movement because of the presence of high permeability streaks.
Excessive water production from the high permeability upper sandstone reservoirs causes major economic, operational, and environmental problems during oilfield operations. Water production can also cause secondary problems such as sand production, corrosion, emulsion, and scale formation. Although the reservoir has been on production more than 50 years, water sources are still considered to be a mystery. Many different concepts and scenarios have been considered such as channeling behind the casing, highly conductive faults, channeling through the high-permeability zones and high-permeability streaks, which accelerated water production. As a result of this issue, water breakthrough at crested wells in an edge-water driven upper reservoir and water production has increased.
Inflow Control Devices (ICD) completion has been installed in upper reservoir wells to overcome water production challenges. Low reservoir pressure is a major challenge for upper reservoir wells ICD completion design. During the course of this paper, Khafji field water encroachment study results have been discussed to show the latest water front movement expected scenario. In addition, ICD-completed wells performance was analyzed and compared to cemented perforated liner completion wells (Non-ICD completion) offset wells in upper reservoir. The parameters that were used during the ICD-completion design to overcome the main field challenges were highlighted. ICD completed wells showed positive performance results in water production control and higher oil production rate.
Moawad, Taha Mousrafa (Al-Khafji Joint Operations) | Salah, Mohamed (Schlumberger) | Al-dhafeeri, Abdullah (Al-Khafji Joint Operations) | Mohammed, Tawakol Ibrahim (Al-Khafji Joint Operations) | Abd Elfattah, Mahmoud Mohamed (Schlumberger)
First application of Inflow Control Devices (ICDs) completion is implemented in long openhole section with an average permeability of 3000 md sandstone-reservoir in offshore Khafji field. This work illustrates the best evaluation to design and to select the process for using ICD in long openhole section of 1,900 ft.
The present paper discusses the challenges which faced to install the first ICD completion focusing on reservoir/production challenges including heel-to-toe effect, uneven drainage across horizontal section, early water breakthrough from high permeability intervals, water coning / fingering, sand production and hole stability issues. The second challenge category includes drilling fluid selection with heavy weight drilling mud due to hole stability issues and chemical treatment process.
Cleaning of water -base mud filter cake at ICD completion by using a treatment fluid that will attach to the mud cake to be lifted up in order to disperse all the mud particles passing through the screen will be discussed in this work. The treatment combines chelating agent and enzyme breaker; such treatments ensure removal of both polymer components and CaCO3 bridging particles in the mud filter cake as single step. Laboratory test results and fluid preparation will be discussed in details later.
The initial well testing result showed a successful completion deployment of ICD in a long openhole section to TD with high production rate and zero water cut. Well production performance will be compared with offset wells to evaluate ICD completion value in terms of reservoir and production optimization.
Excessive water production affects profitability of oil and gas. It reduces hydrocarbons production rates. In addition, it leads to corrosion, scale formation, and extra costs in constructing large water handling facilities. One of the key issues is to correctly identify the source of the excess water and develop the appropriate treatment. The targeted reservoir of this study is a naturally fractured carbonate reservoir that displays super K which are areas of extremely high permeability that can produce substantial volumes of both oil and water. Super K zones can significantly enhance recovery per well, however, these zones present significant challenges at the onset of water production because they can dominate the flow in the wellbore resulting in high water loading.
One chemical method to deal with the excessive water production problems is the use of Relative Permeability Modifiers (RPM). It reduces water cut of the produced fluids without significantly damaging hydrocarbon production. Unfortunately, most of the developed RPMs are suitable for Sandston reservoirs rather than carbonate ones. There have been no successful applications of materials that display a relative permeability modification in reservoirs of this type. It is estimated that carbonate reservoirs contain more than 60% of the world's remaining oil reserves so the development of new technologies that enable these reserves to be tapped are extremely worthwhile.
The development of novel materials which could tackle excess water production in carbonate wells would represent a radical, and much needed step-change technology for the extraction of the significant reserves trapped in reservoirs of this type. This paper describes a comprehensive review of different chemical methods for water control and reports on lab tests to examine the performance of several commercially available RPMs to reduce water-cut in carbonate cores. An advanced work to create and develop a relative permeability modifier (RPM) to control water production in naturally fractured carbonate fields with super K permeability is also described in this paper.