Steam injection is one of the most common EOR methods adapted in heavy oil reservoirs. Steam improves the heavy oil mobility by reducing its viscosity via temperature increase. Steam Flood and Steam Cycle are the primary approaches applied widely in a steam EOR project.
Profit maximization of steam flood projects require good reservoir management practices including regular reviews to optimize steam injection. Steam management adjustments are both simple and complex. The steam management adjustments react against performance expectations, such as early or late production response at the production wells
An integrated work effort by the reservoir management team is imperative in the daily surveillance work. This work requires using geological maps, fence diagrams, permeability maps for identifying possible sand channels and preferential steam path, injection profile logs, injection rates/pressure and production data. Synthesizing all this data determines best locations to redistribute available steam. Expected response is lower steam oil ratios, lower wellhead temperature and lower well water cut rates.
This paper, it summarizes the workflow used for steam optimization process in one of Oman steam flood project. The workflow covers the identification through implementation phase where steam adjustments are required. These phases include review of geological description, petrophysical properties, and production and injection trends. This paper also discusses final KPI measures used to judge successful steam management adjustments.
Halokinesis has strongly stimuluses the Abu Dhabi petroleum system. During the Late Precambrian, the basement terranes of the Arabian and adjoining plates were fused along the northeastern margin of the African Gondwanaland plate. This phase was followed by continental rifting and intra-continental extension. The Arabian Infracambrian extensional system established rifted salt basins in the Zagros region, South Oman and in the Arabian Gulf. The Hormuz salt in these areas contains basalt and rhyolite, suggesting tectonic extension at this time. The Zagros thrust fault and Dibba transform fault define the current limits of the Hormuz Complex of the Arabian Gulf. As a passive margin during Paleozoic time, the Arabian plate accumulated a continentally influenced shallow marine sequence characterized by interbedded siltstones, sandstones, shales and carbonates sediments. The Late Ordovician-Early Silurian glaciation interrupted the Paleozoic deposition by lowering sea level in the Late Silurian and Late Carboniferous-Early Permian glaciation.
Salt movement was started an extensional phase in Permo-Jurassic with the Neo-Tethys opening and basement faults reactivation. Followed by Cretaceous compression stress due to Afro-Arabian Plate movement. The third phase happened by Late Cretaceous with the closing of the Neo-Tethys. The salt was finally pierced to the surface by Mid Tertiary compression stress forces accompanied with Oman thrusting and Zagros folding. Since Miocene uplift, the salt movement extended until present day onwards. Previously, the pierced salt was considered stacked, but subsidence measurements indicating salt is still moving in some islands reaching about 2cm per year.
This paper uses 3D seismic, core data and outcrops investigations to assess the geometry, kinematics, and the halokinetic phases that stimuluses the hydrocarbon exploration targets. The paper revisited the flowage phases of the salt in Abu Dhabi, investigated the accompanying fault geometries and relate this to the structural styles. The diapiric anticlines forming during salt movement phases forming domal structures with radial faults. Contradicting what is known, the Miocene-recent strata are tilted indicating the continuation of the salt movement. The Hormuz salt is characterized by a regionally consistent stratigraphy, formed of evaporites interbedded with clastic and carbonate sediments with dolomite intervals and vein intrusions of volcanic rocks.
Interpreted faults were categorized into three families, Type I comprising domal radial faults, Type II representing faults triggered salt movements and Type III describing salt movements triggered faults. The first type is characterizing itself by its location relative to the crystal parts of the domes. The relatively low overburden pressure at the crest of the diapir and the original high dip angles of these fault planes favor salt intrusions near the diapir crest. Depending on the salt movement phases, the generated cycles of these faults, are characterized by different dips and areas of extension, while the other two categories can be differentiated as well. At the time of salt movement initiation, these faults were incipiently intruded by salt for relieving the intense internal overpressure in the salt body. These pressures are due to the compression forces associated with the salt movement, the buoyancy effects compensating the density difference between salt and overlying sediments and the tectonic compression forces. The latter is the reasonable mechanisms that allow salt penetration along fault planes and bedding planes.
This paper provides evidences that salt movements impact the petroleum system, especially traps, as if the salt movement preceding the hydrocarbon migration, this leads to faults sealing and the reverse is also applied.
Moiseenkov, Alexey (Petroleum Development Oman) | Smirnov, Dmitrii (Petroleum Development Oman) | Mahajan, Sandeep (Petroleum Development Oman) | Al Hadhrami, Abdullah (Petroleum Development Oman) | Al Azizi, Issa (Petroleum Development Oman) | Shabibi, Hilal (Petroleum Development Oman) | Balushi, Yousuf (Petroleum Development Oman) | Omairi, Mahmood (Petroleum Development Oman) | Rashdi, Mansoor (Petroleum Development Oman)
There have been many oil and gas field discoveries in the Cambrian Ara Group intra-salt carbonate rocks in the South Oman Salt Basin. These carbonates represent self-charging petroleum system with over-pressured hydrocarbon accumulation in dolomitized rock encased in the salt. Drilling and completion wells going through salt is challenging. Salt creeping behavior results in issues of stuck pipe during drilling operations, casings deformation and collapse that have led to well suspension and abandonment.
The full set of the available historical data analyzed to identify magnitude and history of the problem. The study conducted to estimate of salt creep magnitude, to assess the effect of the salt creep on cement quality, drilling and completion risks. The risk of salt creep on the drilling, completion and long-term well integrity was evaluated with multi-disciplinary integration of geological, geomechanical, petrophysical and well engineering aspects to minimize and mitigate the salt creeping risks. In addition to identify root cause for completion failure and providing recommendations to drilling practices, cementation and completion design that can improve well delivery process.
Salt creep behavior presents drilling challenges associated with excessive torque, stuck pipe, casing deformation, and poor cementing job. Salt creep associated risks to drilling and well integrity should be managed and mitigated. Key study findings captured for wells designs were: Salt creep rate increases with depth, salt thickness and differential stress (function of MW) Non uniform loading decreases the collapse rating of the casing and results in casing deformation Non-uniform loading likely due to poor cementing, interface between rigid carbonate intervals and salt, and irregular open hole quality.
Salt creep rate increases with depth, salt thickness and differential stress (function of MW)
Non uniform loading decreases the collapse rating of the casing and results in casing deformation
Non-uniform loading likely due to poor cementing, interface between rigid carbonate intervals and salt, and irregular open hole quality.
Studied casing collapse cases could likely be attributed to several factors or combinations of factors such as salt mobility behavior, drilling with low MW, poor cement jobs and loss of internal hydrostatic support for the casing after cement job between liners lap. The improved multi-disciplinary understanding of salt creep is vital to reduce drilling and completion costs, unnecessary well abandonment and achieve good life cycle well integrity i.e. avoid extra side-track and workover cost due to integrity issues. The best practices and conclusions summarized in the study for drilling and completion design expected to benefit the exploration and development projects for the salt encased carbonate reservoirs around the globe.
Zhao, Wenyang (ADNOC Offshore) | Al-Neaimi, Ahmed Khaleefa (ADNOC Offshore) | Sarsekov, Arlen (ADNOC Offshore) | Saif, Omar Yousef (ADNOC Offshore) | Abed, Abdalla Abdel Fatah (ADNOC Offshore) | Al-Feky, Mohamed Helmy (ADNOC Offshore)
With an increased maturity and complexity of the reservoir, an optimized field development plan implementation is critical to achieve the planned target and to ensure an optimum field recovery. The paper presents an optimized process with uncertainty analysis based on Monte Carlo Simulation for the purpose of optimizing the Medium Term Development Plan (MTDP) implementation.
The five year development plan of this giant offshore field has been successfully assessed based on this optimized approach. The integrated workflow consists of four main parts, including actual field technical rate tracking, DBC optimization, simulation results, and effective capacity with Monte Carlo simulation embedded. The dynamic situations could be taken care with these seamless coupled tools. The actual field technical rate has been tracked on a monthly base through a systematic and automated process. The reference decline ratio has been assumed based on historical production decline analysis. Besides, a floating decline based on simulation results is also added in order to capture the well closure due to gas production limitation. Field technical rate is the fundamental input for field development plan to derive the field sustainable oil production rate. It is dependent on both existing wells' performance and future wells' planning. Both the expected gain and drilling schedule of the planned wells are crucial to achieve the production target with reservoir pressure appropriately supported. Voidage Replacement Ratio has been applied to balance production and injection. Drilling plan could be revised accordingly. The production and injection balance can be visualized in the effective capacity tool, which will be used to further optimize the producer and injector plans. The requirements of producers and injectors are summarized and imported into the DBC optimization tool to evaluate new drilling schedule, which will be used in the effective capacity tool for an iteration loop.
Uncertainty analysis is critical to assure a field development plan. Uncertainties have been evaluated based on the factors' most probable range. Five major assumptions, including expected gain from new wells, drilling duration, decline ratio, put-on-production time, and operating efficiency, have been evaluated to assess the uncertainty. Mitigation actions could be proposed to assure the production plan.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
The conventional well stimulation treatments have been used in the oil and gas wells for long time to remove formation damage or skin in order to enhance the well production and be able to achieve economic rates.
Wireline Applied Stimulation Pulsing (WASP®) is a prominent new technology that is gaining more grounds in the well stimulation for oil producer and water injector wells. WASP® is an electro-hydraulic technology that generates repeatable, high power hydraulic pressure pulses downhole over the entire desired interval. The repeated pulsing stimulates the near wellbore area, breaks up scale and causing tensile failures in formation rock, thus creating mini fractures/fissures for new flow paths and removing formation damage or skin caused by scale, fines etc. that were blocking perforations, slotted liners, sand screens or gravel packs, resulting in improved inflow.
Petrogas Exploration and Development recently conducted a WASP® campaign trial that is the first application in the middle east in four vertical wells in the south of Oman oil fields. The wells were Well-A, Well-B, Well-C and Well-D. The vertical wells were completed on the Gharif and Al Khlata sandstone oil reservoirs, which contain relatively medium oil with a viscosity range of 44-239 cP. All the pay zones were perforated, except for Well-B which was completed with gravel pack. The wells were completed with artificial lift including PCP pumps and beam pumps with polish rod strings. It was understood that the poor/low production performance of the candidate wells was due to the high skin, caused by the damaged gravel pack and plugged perforations. The WASP® tool specifications that was run for the treatments of the wells were 2.750" in diameter, and the length was approximately 11.6 m. The conveyance was on electrical wireline cable by using a standard logging truck.
The results of the WASP® treatments jobs have shown mixed results but generally Well-A/B, Well-C and Well-D showed improvement in well performance and consequently in the oil gains. In fact, in Well-C in Aseel field had the highest production rate increased by more than threefold - a remarkable improvement. The other wells are still in the monitoring stage. The operation performance of WASP® treatments went smoothly without any operational issues or lost time in all the jobs. WASP® technology demonstrated that it is an attractive alternative method to the conventional well stimulation methods that involve the use of hydraulic fracturing and injection of acid, solvents and deimulsifiers. These conventional well stimulation methods have limitations in the treatment of the pay zone and operationally intensive. WASP® technology is proven to be more effective, safe (HSE compliant), less time consuming and thus cost effective. Petrogas is now considering applying the WASP® technology to the water injectors.
Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties.
Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk.
Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data.
Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency.
Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within Gharif formation.
This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts.
A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells.
The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes.
Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach.
The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.