C. Ferreira, Flavio (Schlumberger) | Stukan, Mikhail (Schlumberger) | Liang, Lin (Schlumberger) | Souza, Andre (Schlumberger) | Venkataramanan, Lalitha (Schlumberger) | Beletskaya, Anna (Schlumberger) | Dias, Daniel (Schlumberger) | Dantas da Silva, Marianna (Schlumberger)
Oil-water relative permeability and capillary pressure are key inputs for multiphase reservoir simulations. These data are significantly impacted by the wettability state in the reservoir and by the pore space characteristics of the rock. However, in the laboratory, there are several challenges related to the validation and interpretation of the special core analysis (SCAL) measurements. They are mostly associated with the core preservation or restoration processes and resulting wettability states. To improve dynamic reservoir rock typing (DRRT) process, a new model, describing the change of wettability fraction with depth in mixed-wet reservoirs, is proposed. The proposed model is based on solid physics describing the interactions between the rock grain surfaces and the fluids filling the pore space. First, the model considers the oil migration from the source rock into the originally water-wet reservoir and the corresponding capillary pressure rise, as the height above the free water level (HAFWL) is progressively increased. Then, oil-wet and water-wet fractions are estimated for different static reservoir rock types (SRRT) and different HAFWL, based on the wettability change potential of the rock-fluid system and oil-water capillary pressure curves. Additionally, mixed-wet capillary pressure and relative permeability curves are estimated for both oil displacing water (drainage) and water displacing oil (imbibition) processes, based on the estimated mixed-wet fractions and single-wet curves. We discussed the model assumptions and its parameters' uncertainties. We prepared a comprehensive sensitivity study on the impact of wettability variability with depth on oil recovery results. This study used a synthetic carbonate-reservoir simulation model, under waterflooding, by incorporating the concept of DRRT defined according to the different SRRT and estimated wettability fractions. The results showed a significant impact of wettability variability on oil in place and reserves estimates for waterflooding processes in typical complex, mixed-wet carbonate reservoirs, such as the ones found in the Brazilian Pre-Salt. We also discuss the potential impact of wettability change with depth on well logs like resistivity, nuclear magnetic resonance (NMR) and dielectric logs. The proposed reservoir wettability model and its corresponding DRRT workflow is relatively simple and widely applicable, and may significantly improve reservoir simulation and wettability uncertainty analysis. It also explicitly identifies the required wettability parameters to be obtained from laboratory experiments and well logs. Finally, the proposed model may be integrated with special core analysis, well logs and digital-rock analysis.
Reservoir monitoring carried out using previous-generation pulsed neutron logging tools worked well in ideal borehole conditions. However, evaluations were complicated in non-ideal borehole environments, such as gas in the borehole, which affects capture cross section, sigma, and thermal neutron porosity measurements, changing borehole fluid holdup, which confuses carbon-oxygen interpretation, and identifying hydrocarbon type using only neutron porosity when oil density and hydrogen index are very low or open hole (OH) data are unavailable.
A new-generation pulsed neutron logging tool has been introduced that benefits from a high output neutron generator, two LaBr3 detectors, one yttrium aluminum perovskite (YAP) detector, one neutron source monitor, and an improved acquisition sequence. It provides self-compensated measurements of sigma and thermal neutron porosity, along with full capture and inelastic spectroscopy, including total organic carbon (TOC) and carbon-oxygen ratios. This tool also measures a new formation property called the fast neutron cross section (FNXS), which provides a gas saturation estimate independent of conventional methods. All measurements are recorded in the same logging pass, thus reducing overall logging operation time.
Pulsed neutron measurements were acquired in lateral wells using the new generation tool in the A field, onshore Abu Dhabi. Through lateral sections with changing oil, water, and gas holdups in the borehole, and in changing completion environments, robust sigma and neutron porosity measurements were acquired with the help of the automatic self-compensation algorithm. Neutron porosity helped quantify gas saturations where the OH data are available and of good quality. However, in zones where it is not possible to use the neutron porosity by itself (for example, in zones with missing or uncertain OH results), the FNXS measurement provided an independent estimate of gas presence and saturation. FNXS of brine (7.5 1/m), calcite (7.5), and oil (6.0 to 7.0), are similar and strongly contrast with the FNXS of gas (1.5 to 2.5). Thus, the measurement is insensitive to porosity by itself but highly sensitive to gas presence. A crossplot of thermal neutron porosity (TPHI) and FNXS provides a robust estimate of gas saturation in wells where OH results are uncertain or not available.
This paper presents, through multiple examples, a first comprehensive look at the various challenges faced while logging lateral wells in a light oil environment and showcases how a combination of self-compensated measurements coupled with the new measurement of FNXS can make data interpretation more robust in complex borehole and completion environments.
Summary: Abrupt and large changes in the earth properties (velocities) can cause conversion of the compressional waves to converted mode energy. Such converted waves could be recorded on the towed streamer seismic data. If they are not identified and removed early they can mislead the interpretation. In this paper, we are showing the successful application of the converted wave attenuation (CWA) workflow on the seismic data from the Mediterranean See, Offshore Egypt. Data is acquired with latest broadband technique and went through several iterations of velocity model building. The presence of the strong converted waves has threatened to undermine velocity model building and interpretation effort. The benefit of presented workflow is that it identifies and models the converted energy pre-stack pre-migration, however the subtraction is done pre-stack post-migration. Post-imaging subtraction gives improved flexibility in signal protection and improvements in the S/N ratio, especially in the areas where the separation of the converted more and compressional energy is small. Presented workflow is universally applicable to any areas where the converted modes occur.
Haddad, Mohamed (ADNOC Offshore) | Rashed Al-Aleeli, Ahmed (ADNOC Offshore) | Toki, Takahiro (ADNOC Offshore) | Pratap Narayan Singh, Rudra (ADNOC Offshore) | Gumarov, Salamat (Schlumberger) | Benelkadi, Said (Schlumberger) | Bianco, Eduardo (Schlumberger) | Mitchel, Craig (Schlumberger) | Burton, Phil (Schlumberger)
Injection of drilling waste into subsurface formations proves to be an environmentally-friendly and cost-effective waste management method that complies with zero discharge requirements. It has now become the technology of choice in offshore Abu Dhabi.
The aim of cuttings reinjection (CRI) is to mitigate risks associated with subsurface waste injection and reduce cuttings processing time and cost. In order to meet these goals, a cuttings reinjection subsurface assurance methodology was developed to improve cuttings processing and continuously monitor drilling waste injection operations.
Preparing for CRI operations required extensive drilling cuttings slurry testing to minimize processing time and develop optimum particle size distribution to reduce cost and increase the injected waste volume. The improvements were accompanied by downhole pressure and temperature monitoring of the injection well, thus facilitating analysis of injection pressures. Fracture containment was verified through a combination of pressure decline analysis, periodic injectivity test, temperature survey, and periodic modelling for fracture waste domain mapping. A backup injection well was used also as an observation well to monitor the pressure signitures in the injection formation.
More than 1 million barrels of drill cuttings and associated drilling waste have been safely and successfully disposed of into a single injection zone of CRI well over three years of operations.
The cuttings reinjection subsurface assurance method optimizes grinded cuttings particle size distribution, detects and identifies potential risks to provide mitigation options to prolong the life of the injector.
The proactive subsurface injection monitoring-assurance program was built into the fit for purpose CRI injection procedure to continually avoid injecting any rejected hard material, improve and update the process as per subsurface injection pressure responses, thus reducing processing time and cost, mitigating injection risks, and extending the injection well life.
This paper presents the unique and technically challenging cuttings slurry properties design and pressure interpretation experience learned in this project; the enhancement of cuttings processing helped increase injection volumes and an in-depth interpretation of fracture behavior which behaved like a risk-prevention tool with mitigation options. Significant enhancement was developed in slurry treatment procedures to avoid injectivity loss and maximize the disposal capacity.
In Middle East carbonate reservoirs, power water injector (PWI) wells are typically completed with long openhole laterals. The reservoir contact provides pressure support and enhances sweep efficiency in the low-transmissibility reservoirs. Due to the wells deviation and length, coiled tubing (CT) interventions are required to successfully enter and identify each lateral, as well as to remove formation damage by pumping the matrix stimulation treatment across entire laterals.
During such CT interventions, laterals are accessed thanks to a hydraulically operated lateral identification tool (LIT), while the stimulation treatment is pumped through a ball-drop-activated high-pressure jetting nozzle (HPJN). LIT and HPJN are efficiently operated by monitoring downhole pressure values both inside and outside of the bottomhole assembly, in real time thanks to CT fiber-optic telemetry. Those downhole pressure readings further assist in optimizing the pumping rate during the job, while keeping it below the fracturing pressure. Finally, the telemetry provides support for gamma ray (GR) logging, which facilitates depth control and lateral identification.
This study features a case history during which the matrix stimulation treatment was conducted in two separate CT runs for both laterals of the well. For the first run, the CT initially entered L-0 following the natural path of the well, whereas L-1 was accessed by activating the LIT. Correct lateral entry was confirmed by matching the acquired GR readings with reference logs. After successfully accessing L-1 and reaching its maximum depth, a ¾-in. ball was dropped to isolate the LIT and activate the HPJN for stimulation.
During the second run, as the CT entered L-0, GR monitoring was used to confirm lateral accessibility. The stimulation treatment was pumped after reaching maximum depth and isolating the HPJN. During the stimulation of each lateral, 20% viscoelastic diverting acid was utilized for diverting from high-intake zones and 20% HCl to stimulate damaged/tight zones.
This operation illustrates how downhole pressure gauge readings are used to sequentially operate the LIT efficiently and activate the HPJN, as well as to pump the matrix stimulation treatment below the fracturing pressure. Real-time GR readings, meanwhile, are used for depth control and to correctly identify laterals.
Schlumberger has developed a unique PN-1 membrane technology in collaboration with Petronas. The technology is unique in combining two distinct types of membrane fibers in one single membrane module to reduce the overall membrane requirement by 10% and offers overall CAPEX and OPEX savings. The PN-1 technology was developed in 2009 and was successfully tested onshore and offshore facilities for total 5 years.
The PN-1 technology was first deployed in an onshore gas processing facility which was awarded to Schlumberger in 2013. The facility comprised of membrane pretreatment which is mainly gas dehydration, dew pointing followed by several PN-1 membranes in first stage. The membrane design was unique to handle variable inlet feed conditions from 25 to 12% CO2 inlet gas and outlet gas at 8% CO2. The feed gas design flowrate is 700 MMSCFD and at 750 psig operating pressure. Since this is an onshore gas receiving station, the processing trains should be able to handle variable inlet CO2 concentration in the inlet feed gas and particularly membranes.
Schlumberger engineered the entire pretreatment system, membrane and mercaptan removal system. The entire system was delivered and commissioned by Schlumberger on time and was brought online in 2017. The PN-1 membrane system was successful in meeting the required outlet gas CO2 specification while retaining maximum hydrocarbons in the product gas.
El Hawy, Ahmed (Schlumberger) | Al Busaidi, Adil (Schlumberger) | Vasquez Bautista, Ramiro Oswaldo (Schlumberger) | Awadallah, Muhannad (Schlumberger) | R. Heidari, Mohammad (Schlumberger) | Saidi, Khaled (Schlumberger) | Escamilla, Barton (Schlumberger) | Al Abri, Zahran (Petroleum Development Oman) | deBoehmler, Guy (Petroleum Development Oman) | Al Harthi, Said (Petroleum Development Oman) | Haeser, Patrick (Petroleum Development Oman) | Al Riyami, Khaleel (Petroleum Development Oman) | Picha, Mahesh (Petroleum Development Oman)
As one of the worst oil & gas business downturns struck, the need for a revolutionary approach of drilling was needed. Optimization was the key word during that period, it was about time to look back at drilling fundamentals, review and learn from previous failures and lessons while establishing new foundation for a transformed yet successful process that ensured an all-time historical success.
While many trials of drilling optimization initiatives were executed over the years, inconsistent drilling performance delivery and repetitive failures continued to raise a red flag each time for variety of reasons.
From challenges achieving required performance levels and dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales in the north, and through fragile weak formations in the south to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones.
While cost optimization was the trend during the downturn, there was no better option to achieve desired financial results for both operator and service provider than the inclusion of the drilling optimization in action initiative into every well drilling program, it was proven to be an ultimate win-win technical and business solution.
Pore pressure and wellbore stability estimation in real-time has become a mandatory service in any situation where drilling hazards are expected and particularly in the cases of deep water, exploration, geologically complex and extended reach settings. The basic workflow assumes that under-compaction is the primary cause of abnormal pore pressure generation (
Advanced mud gas interpretation and cavings (pieces of rock not drilled by bit or reamers) analysis have become important tools in real time pore pressure and wellbore stability monitoring and are used to determine the approach to a structural deformity (faults/fractures) or the presence of elevated pressures at the crest of a permeable formation, either due to lateral transfer or gas buoyancy. Analysis of cavings shape, structure and mode of generation helps to determine the current borehole condition and whether the mud weight (MW) needs to be raised to control the problem, or just modifying the drilling parameters would suffice. The presence of connection gas peaks aids the pore pressure analyst to estimate the pore pressure across a permeable formation by associating its magnitude and its relationship to dynamic (equivalent circulating density - ECD) and static (equivalent static density - ESD) environments. The use of Managed Pressure Drilling (MPD) to maintain a constant backpressure across the annulus, negates this fluctuating static to dynamic environment and hence affects the use of mud gas behavior to determine if the prevailing MW column is sufficient to provide static overbalance, but workflows to address this issue have been defined over the years. Although, the industry is currently beginning to use these secondary indicators into their workflows, there is no standard that incorporates these sources into a single, cohesive workflow.
This paper presents an integrated approach to pore pressure prediction and managing drilling risk by incorporating multiple sources of information beyond classical log-based techniques. It demonstrates the value of advanced mud gas interpretation, drilling mechanics interpretation, cavings and drilling parameter analysis to optimize the pore pressure model in real-time and enhance the traditional techniques.
Gao, Xiaofei (CNOOC-Shenzhen) | Wu, Yuze (CNOOC-Shenzhen) | Shen, Xu (CNOOC-Shenzhen) | Dai, Ling (CNOOC-Shenzhen) | Chang, Botao (Schlumberger) | Wang, Chao (Schlumberger) | He, Chengwen (Schlumberger)
Development of lithological reservoirs is becoming vital in the Pearl River Mouth basin of the South China Sea. One of these is the Neogene M lithological reservoir in which the deposition of a paleodelta over multiple periods caused a complex profile including severe heterogeneity, rapid lateral property change, poor sand connectivity, and irregular thickness variation (0.5 to 12 m) with interbeds. The current development scope is approaching the predicted eastern sand-pinchout line, making it necessary to identify key points as "golden spikes" to shape the sand bodies’ spatial distribution profile, internal characterization, and pinchout points. based on the sand bodies’ distribution network, drilling and production techniques can be specifically configured to push the development limit as much as possible by efficiently squeezing remaining oil.
In the horizontal well campaign, five appraisal wells are important golden spikes where interwell structural and stratigraphic uncertainties are high due to limited resolution of 3D seismic and sequence stratigraphic data and limited depth-of-investigation (DOI) of conventional logging data. A high-definition deep-looking inversion service was identified to balance resolution and DOI. This novel inversion stochastically analyzes hundreds of formation models using the Metropolis-coupled Markov-chain Monte-Carlo method and then identifies multiple layers (more than three) with 6 m DOI, formation resistivity, anisotropy and dip. With the key resolution-DOI balance, this deep-looking inversion can reveal high-definition interwell details and set a series of golden spikes to identify sand superposition configuration and pinchout points. Within the refined 3D reservoir model, the geo-steering efficiency, completion configuration, and waterflooding stimulation efficiency could be optimized for maximum recovery. Furthermore, a reasonable well pattern arrangement could be developed to sweep the predicted remaining oil and progressively push the development limit.
As evident from ten horizontal wells, high-definition interwell reservoir details were revealed by describing up to four boundaries and five layers simultaneously within maximum 5-m distance from borehole. The golden spikes characterized sand bodies’ profile and their pinchout points. Compared to the prognosis, the southeast margin has been moved to the west. Smooth trajectories were proactively steered to chase irregular sand bodies with minimal loss. Based on the refined 3D reservoir model, proper completion configurations were designed to accommodate the variable properties in this reservoir. One horizontal water-injection well focused on specific discontinuous sand bodies for an average 1.6MPa (megapascal) /well pressure recovery and total 126,000 barrels/year incremental oil. Oil recovery reached 13% within 3.5 years of production, faster than the prognosis. Under current development led by this integrated service, four wells were planned towards updated eastern pinchout line to exploit the remaining oil as much as possible. With increasing distance from the platform, laterals can be placed accurately to achieve objectives with high drilling efficiency and less drilling risk by minimizing unnecessary trajectory adjustments.
From resolution-DOI balance to the identification of golden spikes, this deep-looking inversion could constrain 3D seismic and sequence stratigraphic interpretation to refine the large-scale reservoir model. Considering drilling and production methods, this integrated service could effectively push the development to the potential limit.
Primasari, Indah (PT Pertamina Hulu Mahakam) | Wijaya, Geraldie Lukman (PT Pertamina Hulu Mahakam) | Hadi, Aen Nuril (PT Pertamina Hulu Mahakam) | Chendrika, Lusiana (Schlumberger) | Merati, Putu Astari (Schlumberger)
Handil is a mature oil and gas field with dozens of wells drilled within 70-m distance. It has been developed since 1975 and operated by Indonesian national oil company, PT Pertamina Hulu Mahakam. Handil shallow reservoirs are located at depths between 200 and 1500 m true vertical depth (TVD). It has strong aquifer support and unconsolidated permeable sandstone reservoirs with poorly sorted grain size, requiring gravel pack completion. Since 2005, there have been 39 wells completed with gravel pack, contributing 40% of total Handil field production. Handil gravel pack wells are facing productivity impairment; several production tests indicated that 30% of the completed zones have a very low productivity index (less than 0.5 STB/D/psi) after a few years of production.
Organic clay acid (OCA) was proposed as a matrix acidizing technology to dissolve the fines in the critical near-wellbore matrix. For many years, matrix acidizing has been used to remove formation damage or improve productivity in formations containing siliceous clay. The most commonly used treatment fluid is mud acid, which is a mixture of hydrofluoric acid (HF) and hydrochloric acid (HCl). In many conventional mud acid treatments, after an initially good response to the treatment, the production falls to levels similar to those before the treatment; this is thought to be due to the precipitation from the reaction of HF with silica material on feldspar/clay, which results in more hydrated silica gel. Unlike conventional mud acid, OCA can allow a deeper live-acid penetration into the formation and limit possible reaction-product precipitates, which will enhance the effectiveness of the stimulation treatments.
Two OCA trial treatments were executed through coiled tubing. In the first job, the chemicals created an emulsion that was not compatible with fluid on the surface facilities. Demulsifier treatment on the surface successfully diluted the emulsion. Some adjustments on chemical composition have been applied on the second job, which successfully removed the emulsion. The pilot test yielded total oil production up to 900 BOPD (4,000 BLPD) instantaneous gain with ~80% improvement on productivity by reducing skin from >100 to 5. Currently, both wells are still flowing after 6 months of production. Following this success story, more than 11 OCA jobs are planned to improve the productivity of the existing zones in 2018.
A recent matrix acidizing campaign in Handil shallow wells, highlighting the damage verification, candidate selection, acid chemistry, operational constraints, production results, and future opportunities. The logistics which include the flowback of spent acids and acid neutralization in the swamp area, and the addition of demulsifier in surface facilities will also be discussed. There were no core samples available to run a formation response test to the acid prior to the matrix acidizing treatment.